Aging Nuclear Power Plants: Managing

Plant Life and Decommissioning

September 1993

OTA-E-575

NTIS order #PB94-107588

GPO stock #052-003-01342-8
Recommended Citation:

U.S. Congress, Office of Technology Assessment, Aging Nuclear Power Plants:

Managing Plant Life and Decommissioning, OTA-E-575 (Washington, DC: U.S.

Government Printing Office, September 1993).

ii

For wlc by the LI S (i(ntmmtmt Prln[lng OIIILY

SuperlnIen&n[ (JI [h)cumcnts. NILIII Slop. SSOP, Vt’iih]ng[on. DC 20402-932X”

ISBN 0-16 -041967- 0
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Foreword

urrently, 107 operating nuclear power plants supply over 20 percent of the

Nation’s electricity. As these plants age, issues related to plant lives and

decommissioning are likely to become much more visible and draw more public

attention. This report examines the following: the outlook for safety management

and economic life decisions for the Nation’s existing nuclear power plants as they age, the

prospects for decommissioning, and current and potential Federal efforts that could

contribute to more timely and better informed decisions regarding plant life and

decommissioning. This report is a product of a request by the Senate Committee on

Governmental Affairs and the House Committee on Energy and Commerce and its

Subcommittee on Energy and Power.

After many years of intensive efforts by the U.S. Nuclear Regulatory Commission and

the nuclear power industry, no insurmountable industry-wide safety challenges related to

plant aging have been identified. There are some notable uncertainties for the longer term,

however, that require ongoing research and experience to address. More immediately, many

nuclear power plants already face severe economic pressures in the increasingly

competitive electric power industry. Regarding decommissioning, experience with

decommissioning small reactors and with major maintenance activities at large plants

suggests that the task can be performed with existing technologies. However, several issues

such as waste disposal and site cleanup standards remain unresolved.

OTA appreciates the substantial assistance received from many organizations and

individuals in the course of this study. Members of the advisory panel provided helpful

guidance and advice. Reviewers of the draft report contributed greatly to its accuracy and

completeness. Personnel at the case study facilities shared their valuable experiences and

perspectives. To all of them goes the gratitude of OTA and the personal thanks of the project

staff.

Roger C. Herdman, Director

. . .

Ill
Richard E. Schuler, Chairman

Cornell University

Peter Bradford

New York Public Service

Commission

Richard W. DeVane

Framatome USA, Inc.

William Dornsife

Pennsylvania Department of

Environmental Resources

S. David Freeman

Sacramento Municipal

Utility District

Michael W. Golay

Massachusetts Institute of

Technology

Jerome Goldberg

Florida Power and Light Co.

Howard Hiller

Salomon Brothers

David G. Heel

Medical University of South

Carolina

Leonard Hyman

Merrill Lynch Capital Markets

James Joosten

Organization for Economic

Cooperation and Development/

Nuclear Energy Agency

George J. Konzek

Pacific Northwest Laboratory

Martin J. Pasqualetti

Arizona State University

● Resigned winter 1993 to accept a position with U.S. Department of Enagy.

Robert Pollard

Union of Concerned Scientists

Dan W. Reicher*

Natural Resources Defence Council

Cas Robinson

National Association of Regulatory

Utility Commissioners

formerly, Georgia Public Service

Commission

John J. Taylor

Electric Power Research Institute

H. B. Tucker

Duke Power Co.

Nat Woodson

Westinghouse Electric Corp.

NOTE: OTA appreciates and is grateful for the valuable assistance and thoughtful critiques provided by the advisory panel members, ‘I’he panel

does notj however, necessarily approve, disapprove, or endorse this report. OZ4 assumes full responsibility for the report and the accuracy of

its contents.

iv
Peter Blair Robin Roy

Assistant Director, OTA Project Director

(beginning February 1993)

Energy, Materials, and International Andrew Moyad

Security Division Analyst

Lionel S. Johns

Assistant Director, OTA

(until February 1993) CONTRACTORS

Energy and Materials Program Manager ABZ, Inc.

Chantilly, VA

Emilia Govan

Project Staff

ADMINISTRATIVE STAFF

Lillian Chapman

Office Administrator

Linda Long

Administrative Secretary

Tina Aikens

Secretary

(beginning August 1993)

Energy and Materials Program Manager
Abbreviations

ACRS:

AEA:

ALARA:

ARDUTLR:

ASCE:

ASME:

BRC:

B&WOG:

BWR:

CAAA:

CF:

CLB:

DOE:

DSM:

EEI:

EIA:

EPA:

EPACT:

EPRI:

EQ:

FERC:

GSI:

IAEA:

ICRP:

IEEE:

Advisory Committee on Reactor Safeguards

Atomic Energy Act of 1954, as Amended

as low as is reasonably achievable

age-related degradation unique to license

renewal

American Society of Civil Engineers

American Society of Mechanical

Engineers

below regulatory concern

Babcock and Wilcox Owners’ Group

boiling water reactor

Clean Air Act Amendments of 1990

capacity factor

current licensing basis

U.S. Department of Energy

demand-side management

Edison Electric Institute

U.S. Energy Information Administration

U.S. Environmental Protection Agency

Energy Policy Act of 1992

Electric Power Research Institute

environmental qualification of electrical

equipment

Federal Energy Regulatory Commission

generic safety issue

International Atomic Energy Agency

International Commission on Radiological

Protection

Institute of Electrical and Electronics

Engineers

INPO:

IPA:

IPE:

IRP:

ISFSI:

LLRWPAA:

LLW:

MRS:

NDE:

NERC:

NPAR:

NRC:

NUMARC:

NWPA:

O&M:

PNL:

POL:

PRA:

PWR:

RPV:

SALP:

SOC:

SSCs:

Institute of Nuclear Power Operations

integrated plant assessment

individual plant examinations

integrated resource planning

independent spent fuel storage installation

Low-Level Radioactive Waste Policy

Amendments Act of 1985

low-level radioactive waste

monitored retrievable storage for spent

nuclear fuel

nondestructive examination

North American Electric Reliability

Council

NRC’s Nuclear Plant Aging Research

program

U.S. Nuclear Regulatory Commission

Nuclear Management and Resources

council

Nuclear Waste Policy Act of 1982

operating and maintenance

Pacific Northwest Laboratory

possession-only license

probabilistic risk assessment

pressurized water reactor

reactor pressure vessel

systematic assessment of licensee

performance

statement of considerations accompanying a promulgated regulation

systems, structures, and components

(for additional abbreviations see index)

vi
contents

1 Overview and Policy Issues 1

Summary of Policy Issues 2

Understanding and Managing Aging 6

Aging and Safety 10

Economy of Existing Plants 20

After Retirement: Decommissioning 29

2 Safety of Aging Nuclear Plants 37

Institutions for Assuring the Safety of Aging Plants 44

Safety Practices Addressing Aging 47

Health and Safety Goals for Aging Plants 61

3 Economic Lives of Existing Nuclear

Plants 73

The Changing Electric Utility Context 73

Institutional Issues in Nuclear Plant Economic Life

Decisions 81

Economic Performance of Nuclear Plants 86

Factors Affecting Future Cost and Performance 92

4 Decommissioning Nuclear Power

Plants 101

Residual Radioactivity Standards: How Clean is

Clean Enough? 102

Radioactive Waste Disposal 108

Experience to Date 118

Estimating Costs and Radiation Exposures 132

Reactor Retirement and Financial Requirements 141

5 Case Studies of Nine Operating Plants 149

Calvert Cliffs Case Study (2 plants) 150

Hope Creek Case Study 156

Monticello Case Study 160

Salem Case Study (2 plants) 165

SONGS Case Study (3 plants) 170

I——I

, 1

1

R-.

Index 179 vii
Reviewers and Contributors

Edward C. Abbott

ABZ, Inc.

Satish K. Aggarwal

U.S. Nuclear Regulatory Commission

James V. Bailey

Public Service Electric and Gas Co.

Lake Barrett

U.S. Department of Energy

Stewart Brown

U.S. Nuclear Regulatory Commission

Nick Capik

ABZ, Inc.

John Carey

Electric Power Research Institute

Tom Champion

Consolidated Edison Company

Donald A. Cool

U.S. Nuclear Regulatory Commission

John W. Craig

U.S. Nuclear Regulatory Commission

Quresh Z. Dahodwala

public Service Electric and Gas Co.

Barth W. Doroshuk

Baltimore Gas and Electric Company

C. Gibson Durfee, Jr.

Westinghouse Electric Corporation

Richard Ferriera

Sacramento Municipal Utility District

Michael Finkelstein

U.S. Nuclear Regulatory Commission

Carl V. Giacomazzo

Long Island Power Authority

Dennis Harrison

U.S. Department of Energy

Donald W. Edwards

Yankee Atomic Electric Co.

James G. Hewlett

U.S. Energy Information

Administration

Earl Hill

Halliburtun NUS

L.M. Hill

Shoreham Nuclear Power Station

Mark Holt

Congressional Research Service

Seyavash Karimian

Public Service Electric and Gas Co.

Doris Kelley-Alston

Merrill Lynch Capital Markets

Robert M. Kinosian

California Public Utilities Commission

Jim Krauss

Westinghouse Electric Co.

Thomas LaGuardia

TLG Services, Inc.

Mike Niehoff

Westinghouse Electric Corp.

Philip A. Olson

U.S. General Accounting Office

Ed Parsons

Scientific Ecology Group

George Parkins

Colorado public Utility Commission

James S. Perrin

Public Service Electric and Gas Co.

Mark Petitclair

Northern States Power Co.

Terry Pickens

Northern States Power Co.

Robert M. Quillin

Colorado Department of Health

Harold B. Ray

Southern California Edison Co.

German Reyes

Office of Technology Assessment

Steve Reynolds

U.S. Nuclear Regulatory Commission

Geoffrey Rothwell

Stanford University

Gregory D. Schmalz

Public Service Company of Colorado

Joanne Seder

Office of Technology Assessment

Larry Shao

U.S. Nuclear Regulatory Commission

Ron Simard

Nuclear Management and Resources

council

John Taylor

Brookhaven National Lab

Steve Trovato

Consolidated Edison Company

Gary Vine

EIectric Power Research Institute

Richard Vollmer

U.S. Nuclear Regulatory Commission

Joseph J. Wambold

Southern California Edison Co.

Joseph C. Wang

U.S. Nuclear Regulatory Commission

Don Warembourg

Public Service Company of Colorado

Seymour Weiss

U.S. Nuclear Regulatory Commission

Robert Whitaker

New York State Public Service

Commission

. . . Vlll
L

ong-term prospects for the Nation’s 107 operating

nuclear power plants are increasingly unclear. Proponents argue that these plants, which supply over 20

percent of the Nation’s electricity, are vital to reliable,

economic electricity supplies; have environmental benefits (e.g.,

they emit no greenhouse gases such as carbon dioxide); and

reduce dependence on imported oil. Opponents, however, argue

that nuclear plants bring risks of catastrophic accident, create

unresolved waste disposal problems, and are often uneconomic.

As these plants age, issues related to plant lives and decommissioning are likely to become much more visible and draw more

public attention.

The past few years brought unexpected developments for

nuclear plant lives and decommissioning. Since 1989, six nuclear

power plants have been retired early, well before the expiration

of their NRC operating licenses.1 Owners of several other plants

are investigating the economics of early retirement as well. The

owners of the frost large commercial nuclear power plants

planned for decommissioning anticipate costs much greater than

estimates made only a few years earlier. And after a several year

effort, the two lead plants in a program to demonstrate the NRC’s

plant license renewal process halted or indefinitely deferred their

plans to file an application-in one case as part of an early

retirement decision. While work continues to develop and

eventually demonstrate a regulatory process for license renewal,

it will be several years before the first application is filed and

acted on. Absent license renewal, about 3 dozen operating

nuclear power plants will have to retire in the next 20 years.

1 In this repo~ the term early retirement refers to plant closure prior to expiration

of the operating license issued by the NRC.

Overview

and

Policy

Issues 1

0@4

11
2 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Despite these substantial challenges, there has

also been good news for the U.S. nuclear industry

recently. Reversing a decades long trend of rapid

growth, average nuclear power plant operating

and maintenance costs have decreased in recent

years. Average plant reliability and availability

have improved substantially. Safety performance

has also been good. There have been no core

damage accidents since Three Mile Island in

1979, nor an abnormal number and severity of

events that could have led to core damage, much

less any actual offsite releases of large amounts of

radioactivity. Average occupational radiation

exposures, already well below NRC limits, also

declined substantially.

The Federal Government has a longstanding

role in supporting a safe, environmentally sound,

and economic supply of electricity for the Nation.

Given the recent unexpected developments for

existing nuclear power plants, this report, requested by the Senate Committee on Governmental Affairs and the House Committee on Energy

and Commerce, examines the following:

■ the outlook for the Nation’s existing nuclear

power plants as they age, focusing on safety

management (ch. 2) and economy (ch. 3)

during their remaining operating lives;

■ the outlook for decommissioning (ch. 4); and

■ Federal policies that could help address economic and safety issues for existing nuclear

power plants as they age and as they are

decommissioned (ch. 1).

SUMMARY OF POLICY ISSUES

Current and planned nuclear power plant aging

management practices are designed to identify

and address challenges before they become a

threat and to provide a reasonable assurance of

adequate safety. These practices depend heavily

on elaborate plant maintenance programs and

ongoing research. There will always remain some

risk, however, and continued industry and Federal

regulatory vigilance is crucial. Attention to aging

issues is crucial not just in considering license

renewal but in a plants original license term as

well.

The industry and the NRC are working to

address aging safety issues, but their efforts could

be accelerated to determine better the long-term

prospects for existing plants and to assure adequate long-term safety. For example, the NRC

could intensify its review of aging safety research

for possible regulatory applications. Greater attention to aging safety issues during a plant’s

original license term could also help justify a

substantial simplification of the NRC’s stillundemonstrated license renewal process.

Many nuclear power plants face severe economic pressures. The six early retirements occurring between 1989 and early 1993 give a sense of

the variety of plant-specific issues likely to be

involved in the future, as economic life decisions

are made (box l-A). In three of these decisions,

aging issues played a prominent role. Other

factors besides aging degradation and its effects

on long-term safety and economy have played

prominent roles in determining plant lives and

will continue to do so in the future. Other important factors include: rising operational costs;

disposal of radioactive waste (discussed below);

public attitudes toward nuclear power (box l-B);

and the changing electric industry context, including increased competition and attention to

environmental externalities.

Responsibility for judging a plant’s economic

attractiveness lies primarily with the owning

utility and State regulators. The Federal role is

relatively indirect. However, Federal activities

such as spent fuel disposal, safety regulation, and

policies addressing oil import security, global

climate change, and other environmental challenges can all have major economic impacts both

directly and as they affect the judgments of other

interested parties.

While future economic conditions are highly

uncertain, some analysts have suggested that as

many as 25 plants may be retired in the coming

decade. However, the economy of most nuclear

power plants appears at least moderately attrac-
Chapter 1–Overview and Policy Issues 3

Box 1-A—Taking Early Retirement: Recent Nuclear Power Plant Closures

Six commercial nuclear power plants in the United States have shutdown permanently since 1989, all well

before their operating licenses were due to expire. The reasons behind these closures vary and are summarized

briefly here.

Rancho Seco

This 873 MW pressurized water reactor (PWR) operated almost 15 years. The operating license was issued

to the Sacramento Municipal Utility District (SMUD) on August 16,1974. The plant was shut down on June 7,1989

by a local voter referendum. The basis of the referendum was public concern about plant safety coupled with poor

economic performance.

Shoreham

After years of construction delays, cost overruns, and legal and political battles, the 819 MW boiling water

reactor (BWR) received a full power operating license on April 21,1989. For several years, the State of New York

had refused to accept the emergency evacuation plan proposed by the plant operator, the Long Island Lighting

Co. (LILCO). The State argued that the population living near the plant was too large to evacuate quickly enough

during an accident. As a result, just 2 months before receiving its operating license, on February 28, LILCO agreed

to sell the plant to the State for decommissioning. The utility had pursued the full-power license to demonstrate

the reactor was operable. In preparation for full-power operations, Shoreham was tested intermittently at Iow power

between July 1985 and June 1987. Final shut down was on June 28,1989, and the average fuel burnup in its brief

life was the equivalent of about 2 days of full-power operation.

Fort St. Vrain

The Fort St. Vrain Nuclear Generating Station is a 330 MW high-temperature gas-cooled reactor owned by

the Public Service Co. of Colorado, Although the operating license was issued December 21, 1973, this unique

reactor operated only from 1979 to 1989. The plant was permanently closed August 18, 1989 due to several

concerns: problems with the control rod drive assemblies and the steam generator ring headers, low plant

availability (only about 15 percent), and prohibitive fuel costs. The pIant operator became the first commercial

nuclear utility to receive a possession-only license from the NRC since the Commission adopted decommissioning

rules in 1988.

Yankee Rowe

This 185 MW PWR operated 30 years. The plant began commercial operations on July 1,1961. On October

1, 1991, the reactor was taken offline for a combination of safety reasons and officially retired for related economic

reasons on February 26, 1992. During its review of license renewal efforts, the NRC questioned the extent and

impact of possible age-related embrittlement of the reactor pressure vessel (RPV). The plant owners estimated

that demonstrating the adequacy of the RPV to the NRC’s satisfaction would cost at least $23 million and possibly

more since no agreement had been reached on what would constitute a demonstration of adequacy. Yankee Rowe

also faced previously unexpected poor economic prospects caused by an economic downturn in New England

that resulted in excess generating capacity and large amounts of lower cost competitive power, including much

fueled by natural gas.

San Onofre

San Onofre Nuclear Generating Station Unit 1, a 410 MW PWR operated by Southern California Edison (SCE)

Co., began commercial operation January 1, 1968. Under an agreement with the California Public Utilities

Commission Division of Ratepayer Advocates (DRA), SCE retired the plant November 30, 1992, 12 years prior

(Continued on next page)
4 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Box 1-A–Taking Early Retirement: Recent Nuclear Power Plant Closures--(Continued)

to its license expiration. The settlement was triggered by economic analyses of the costs and benefits of a 2-year,

$135-million capital additions program required at the plant. Steam generator degradation also had resulted in a

modest lifetime capacity factor. The DRA concluded that the plant was uneconomic. Although SCE disagreed with

that assessment, it opted for the retirement settlement rather than pursue either a further hearing process or

assume the risks and rewards of plant operation.

Trojan

The most recent early nuclear plant retirement to date, the 1,175 MW PWR operated for about 16 years before

closing permanently January 4, 1993; the operating license was Issued November 21, 1975. The plant had been

off line since November 9, 1992 due to age-related tube leaks in one of its steam generators. The licensee,

Portland General Electric (PGE), decided earlier in 1992 to closethe plant in 1996 rather than invest the estimated

$200 million needed to replace its steam generators. The recent tube leaks, however, coupled with uncertainty

regarding future regulatory treatment of microflaws in the tubes, led to a final closure decision in January 1993.

For several years, Oregonians repeatedly voted in State-wide referenda on whether to retire the plant. Although

those referenda were defeated by large margins each time, these public campaigns put pressure on the nuclear

plant that PGE did not have to face for its other generating resources.

SOURCE: Office of k4mcttqy Awesmen$ 19S3.

tive, assuming the recent leveling of costs contin- Several decommissioning issues remain unreues.

There is great diversity among plants and plant

performance. Electricity market conditions across

the country are also diverse and changing, making

the long-term prospects for nuclear plant lives

neither uniform nor clear. Thus, no single safety

or economic development is likely to affect

uniformly the future of the Nation’s existing

nuclear power plants. Any tendency to judge the

industry by early retirements may give a misleadingly dim view of the remaining lives of other

plants. Rather, the future of the existing plants are

likely to be determined individually over time as

individual conditions change based on a host of

separate decisions of utilities, State utility commissions, and Federal regulators. Integrated resource planning (IRP) and other elaborate analyses performed by States and utilities to assess

plant economics are likely to play a growing role

in future decisions about whether to continue

operating existing plants.

solved, although work is ongoing to address them.

Residual radioactivity standards, which will determine the level of cleanup necessary at retired

plant sites, are under development at the NRC.

Depending on their stringency, such standards

could have substantial impacts on decommissioning timing and costs. There also remains substantial uncertainty in decommissioning costs and the

adequacy of decommissioning financing in cases

of early retirement or rapid cost escalation.

Although decommissioning costs are uncertain

and large if viewed as a one-time expense, they

are not large relative to lifetime plant production

costs. Greater use could be made of early retirements as case studies to learn about the prospects

for decommissioning costs and performance.

Perhaps of greatest importance, however, is the

future disposal capacity and cost for radioactive

waste. Estimated low-level waste disposal costs

have increased tenfold in the past decade, and

there has been limited progress in developing new

disposal facilities.
Chapter 1-Overview and Policy Issues 5

Box 1-B–Public Views and Existing Nuclear Power Plants

Public perceptions and preferences about the nature of risk and the willingness to incur different types of risk

can be critical issues in determining the future role of existing nuclear power plants. Public views have played a

role in some recent early retirement decisions (see Shoreham, Rancho Seco and Trojan descriptions in box 1 -A.)

In ail three cases, the public pressures were long-standing rather than recent developments. in two of those, the

concerns were combined with troubled economic operating histories.

With regard to decommissioning, public concerns about site remediations standards maybe a significant

factor in cleanup decisions. Under the current NRC framework, decommissioning will lead to license termination

and the potential cessation of regulatory oversight suggesting that public concerns about health and safety

protection may be as great or greater than during plant operations.

As is true for many modern enterprises, the risks and benefits of nuclear power plant operation are imperfectly

understood by the public and, to a lesser degree, by the scientific community.1 Public preferences and

perspectives for different dimensions of risk appear related to several factors, including whether the risk is

voluntary or imposed; involves low probability y, catastrophic accidents, or frequent accidents of limited extent; is

well understood scientifically and by the public; is natural (e.g., radiation exposure from radon or sunlight) or

technological (radiation from nuclear power plant accidents); accompanies highly beneficial activities (e.g., are the

alternatives to nuclear power preferable?); or is familiar or unfamiliar. From the perspective of public perception

and acceptance, nuclear power has scored poorly on these counts.2

At the same time, the nuclear power industry notes that its national public opinion polls over the last several

years have consistently found support for nuclear power. For example, in a 1992 poll three-quarters of the

American public responded that nuclear power should play an important role in future U.S. energy supplies, and

two-thirds of respondents agreed that the existing plants have served the country well.3

1 PUMC perception of risk often varies significantly from the best sdentific evidence. For examde, some

studies have found that public perceptions of risks from nuclear power plant operation are far higher than Indioated

by scientific and medical evidence.

2 p. Slovic, “Perception of Risk From Radiation,” N.K. Sinoldr (cd.) f%ceedngs Of the 25th ~nnmi ~*tin9

of the Nationai CouncilonRad&tion l%otectlonandMeasurernents:No, 11. Radiat)onhteotion T&y-the NCRP

at Shty Years (Bethesda, MD: NCRP, 1990), pp. 73-97; and L.C. Gould et al., Pemwptlons of 7kchnologlca/ Risks

and BenefHs (New York NY: Russel Sage Foundation, 1988).

3A. S. Bi~onti, “ne TWO Faces of Nuclear Energy: U.S. Public Opinion from the Forties tO the IWnetles,”

Speech delivered at the American Nuclear Sodety Annual Meeting, Nov. 18,1992, Vh/~eeches of the Day, Mar.

1, 1993, VO[. 59, No. 10. pp. 317-318.

The nuclear plants currently in operation are through a waiting period of between 5 years and

generally larger and more contaminated than the several decades, allowing short-lived isotopes to

plants decommissioned to date. However, experience with decommissioning small reactors and

with major maintenance activities at large plants

suggests that the task of decommissioning can be

performed with existing technologies. Final decommissioning of all but a few very special cases

will likely not be performed before early in the

next century. Rather, most retired plants will go

decay.

As with many other modem societal activities,

decommissioning cannot provide absolute protection of public health and safety, even if all

radionuclides associated with the plant are removed from a site. For example, there will be

some radiological risks associated with the waste

disposal site, and nonradiological transportation
6 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Table l-A—Federal Policy Considerations UNDERSTANDING AND MANAGING AGING

Assuring adequate aging safety

Accelerate ongoing aging-related safety activities

Simplify the license renewal rule

Revise public participation provisions

Apply NRC’s safety goal policy to aging Issues

Supporting economic decisions

Address aging-related regulatory safety Issues

Address federal obligations for nuclear waste

Expand analyses of nuclear plant economics

Cofund industry R&D for existing plant issues

Policy issues for decommissioning

Revise goals for decommissioning timing and site release

Reconsider adequacy of decommissioning financing

Clarify regulatory policies for low-level waste

Use early retirements as decommissioning case studies

SOURCE: Office of Technology Assessment, 1993.

and occupational risks. Background radiation

from other sources will also remain. The NRC has

recently undertaken a process to revise residual

radioactivity requirements for terminating a license. The NRC could extend this effort to

examine alternatives to its current requirement of

unrestricted site release. For example, because

future exposures depend on land use (e.g., industrial, residential, or agricultural), the NRC could

investigate different radiological standards

matched to restricted land uses.

Several Federal policy considerations relating

to plant safety and economy could potentially

result in more timely and better informed plant

life and decommissioning decisions. These are

listed in table 1-A and are discussed in the three

last sections of the chapter. First, the following

section provides an overview of the current

understanding and management of aging.

I Experience With Plant Aging

The number and size of nuclear power plants

grew rapidly in the 1970s and 1980s. Twenty-five

years ago, there were 11 nuclear power plants in

the United States with an average capacity of

about 180 MW and an average age of 5 years. As

of 1993, the average age of the 107 operating U.S.

nuclear power plants was about 17 years, with an

average capacity of over 900 MW.2 While there

are operating nuclear power plants in all regions

of the Nation except the Rocky Mountain States,

most of the older units are in the Midwest and

along the Atlantic seaboard States (see figure

l-l).

The number of plants outside the United States

has grown rapidly as well. As of 1992, there were

about 300 nuclear power plants in operation in 24

other countries. Although the United States has

the largest number of nuclear power plants of any

country, nuclear power supplies a larger fraction

of total electricity in half of the other countries.

Nuclear plants outside the United States tend to

be newer, many of which have recently come into

service. However, nuclear plant life management

issues are being examined in the international

community, for example, by the Organization of

Economic Cooperation and Development, the

International Atomic Energy Agency and by

individual countries (see figure 1-2).3 Worldwide,

22 new nuclear power plants began operation

between 1990 and 1992, including one in the

United States. During this period a similar number of plants were retired, the majority of which

were in Germany and the former Soviet Union.

z Of the 11 plants operating 25 years ago, 2 remain in service. These are Big Rock Poin4 a 69 MW plant in Michigan, and Haddarn Neck

(also known as Comecticut Yankee), a 569 MW plant. U.S. Department of Energy, Nuclear Reactors Built, Being Built, or Planned: 1991,

DOE/OSTI-82(XLR55, hdy 1992, pp. 1-6, 23, 24.

3 See, e.g., Org anization of Economic Cooperation and Development/Nuclear Energy Agency, “Nuclear Power Plant Aging and Life

Management: A Model Approach Current Status, and Country Comparisons, ” draft, Nov. 3, 1992.
Chapter 1–Overview and Policy Issues 7

‘l--/-

I I

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ml

to ““d.., J,Y?J=
8 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Figure 1-2—An International Framework for Nuclear Plant Life Management

OPTIMIZE NATIONAL

ENERGY STRATEGY

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Purchased energy

EOE?Y / \Y Conservation

Coal option 1 Renewable

1 I I

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/

i External

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information

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ew 

. . ‘

SOURCE: Organization of Economic Cooperation and Development, Nuclear Power Plant Aging and Life Management: A Model Approach, Current

Status, and Country Comparisons, draft, Nov. 3, 1992, p. 6.

w-w
Chapter 1–Overview and Policy Issues 9

Box 1-C–What is Aging Degradation?

Many systems, structures, and components (SSCs) in industrial facilities, including nuclear power plants, are

subject to aging degradation. For nuclear power plants, aging degradation is defined as the cumulative

degradation that occurs with the passage of time in SSCs that can, if unchecked, lead to a loss of function and

an impairment of safety.1 The basic processes of aging are generally, if imperfectly, understood; continuing

experience and research provide ongoing improvements in scientific understanding and ability to predict and

address the effects.

Aging degradation can be observed in a variety of changes in physical properties of metals, concrete, and

other materials in a power plant. These materials may undergo changes in their dimensions, ductility, fatigue

capacity, mechanical or dielectric strength. Aging degradation results from a variety of aging mechanisms, physical

or chemical processes such as fatigue, cracking, embrittlement, wear, erosion, corrosion, and oxidation. These

aging mechanisms act on SSCs due to a challenging environment with high heat and pressure, radiation, reactive

chemicals, and synergistic effects. Some operating practices such as power plant cycling (i.e., changing power

output) and equipment testing can also create stress for plant SSCs.

There is a fairly limited set of degradation mechanisms, a large commonality in materials used, and fairly

similar operating conditions. However, due to the diversity in plant designs, construction and materials used,

operating conditions and histories, and maintenance practices, the specific effects of aging, although similar, are

unique for each plant. Even near-twin units at the same site can have substantial differences in the remaining lives

of major SSCs, based on subtle design or material differences and operating histories.

Among the major aging degradation issues for long-lived SSCs are:

~ reactor pressure vessel embrittlement;

■ steam generator tube corrosion and cracking;

■ environmental qualification for in-containment cables and other electrical equipment; and

■ fatigue, stress corrosion cracking, and other mechanisms that may affect a variety of metal components,

1 us. Nuclear Regulatory Commission IVuclear P/mtAging Research (/VP’A/?) Program P/an, NUREG-1 144

Rev. 2 (Washington, DC: June 1991).

Experience with and understanding of aging Absent actual long-term operating experience

issues continue to increase (box l-C). In total, the

histories of the more than 400 nuclear plants

provide several thousand reactor-years of operating experience with aging. However, because of

the industry’s youth, experience with nuclear

power plants in the second half of their 40-year

licensed lives is limited. This limited experience

with aging can be particularly important for some

major long-lived systems, structures, and components (SSCs) such as the reactor pressure vessel

(RPV), cables, and containment structure that

are intended to function for the full life of a

facility.

for long-lived SSCs, understanding of aging

issues involves engineering analyses and research, often using techniques to simulate accelerated aging on test materials. Retired plants may

also yield lessons about aging by providing

naturally aged SSCs for study. However, the

diversity among plants and their SSCs prevents

simple generalizations about the ultimate effects

and management of aging. In contrast, many other

components have relatively short lives (e.g.,

pumps and valves) and are periodically refurbished or replaced. For these shorter lived SSCs,

engineering analyses and aging research are

supported better by actual operating experience.
10 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

I Managing Aging Degradation

Effective maintenance programs are crucial

to manage aging degradation. Maintenance

involves a variety of methods to predictor detect

aging degradation and other causes of SSC

failure, and to replace or refurbish any affected

SSCs. New maintenance technologies include an

array of improved hardware and procedures that

can benefit the future management of aging

degradation. To “ensure the continuing effectiveness of maintenance for the lifetime of nuclear

power plants, particularly as plants age,” the

NRC promulgated a maintenance rule in 1991 to

become effective in 1996.4 The Institute of

Nuclear Power Operations (INPO), an industry

organization established in 1979 to promote

excellence in nuclear power plant operations, had

previously developed guidelines for effective

maintenance to guide utility practices.5

The process to manage aging is elaborate,

beginning with plant design and construction, and

continuing with maintenance and research. The

SSCs that comprise a nuclear plant were designed

to have sufficient design margins to meet specified minimum lifetime requirements. However, in

the decades since many of today’s plants were

first designed and built, extensive experience and

research have shown that some SSCs degrade

more rapidly than had been expected, while others

last longer. Major examples of more rapid degradation are RPV embrittlement, steam generator

tube degradation, and fatigue and stress corrosion

cracking of piping. The NRC currently devotes

about 20 percent of its $100 million annual

research budget to aging-related projects. The

industry also performs extensive aging-related

research. For example, since its inception in 1973,

the Electric Power Research Institute (EPRI) has

devoted about 15 percent of its nuclear research

budget (currently over $100 million annually) to

understand, detect, and mitigate degradation of

nuclear power plant components.6

Based on research and experience, design

standards have changed considerably since today’s

oldest plants began operating. To assure the

adequacy of older designs in the light of new

technical information, the NRC and the industry

have conducted extensive reviews (most notably

through the NRC’s Systematic Evaluation Program of the late 1970s) and continue to do so.

Two current examples of particular attention are

the NRC’s efforts to examine environmental

qualification of electrical equipment (EQ) and

fatigue as generic safety issues. Factors such as

fatigue, EQ, and embrittlement are more prominent for older plants, not so much because they

have aged more, but because older plant designs

and materials were based on less complete

understanding of aging degradation than newer

plants. Thus, younger plants may be presented

with fewer challenges as they age. For those

plants affected, the costs of addressing these

issues may be substantial.

AGING AND SAFETY

Under normal operating conditions, nuclear

power plants cause limited and generally unmeasurable public health impacts. However, as evidenced by probabilistic risk assessments and

occasional alarming operating events, existing

nuclear power plants also pose a small risk of

catastrophic accidents in which public injury or

fatality could result. Absent effective aging management as discussed above, aging degradation

increases the probability that any SSC will fail to

4

10 CFR 50.65

s In promulgating the rule, the Nuclear Regulatory Commission noted that its recent inspections of maintenance activities found that existing

programs were adequate and improvimg, but there were some areas of weaknesses, and no licensee had formally committed to implement the

INK) standards prior to the rule’s proposal. 56 Federal Register 31321 (July 10, 1991).

G John Carey, Electric Power Research Institute, personal communication January 1993; and Electric Power Research Institute, Research

and Development Plan 1993 (Palo Alto, CA: 1993).
Chapter 1–Overview and Policy Issues I 11

function properly, potentially leading to an accident.7 Continued effort to manage aging at every

plant is thus one important aspect of assuring

safety. However, after many years of intensive

efforts by the NRC and industry, no insurmountable, industry-wide safety challenges related to

aging have been identified, although there are

some notable uncertainties that research continues to address. Some aging-related safety issues

such as more detailed re-examination of fatigue,

EQ, and RPV embrittlement, and implementation

of license renewal regulations will have effects on

plant lives that are yet to be determined. Aside

from plant aging challenges, the NRC and the

industry continue to address other risks and

uncertainties including the performance of human

operators, and containment structures, and the

potential impacts of external events such as

earthquakes and flooding.

Some have suggested that the safety of older

plants is inadequate because those plants were not

designed with the same detailed guidance as

newer plants and therefore often do not meet the

current design standards.8 It is true that a newly

constructed plant identical to older plants could

not be licensed under current NRC regulations.

However, the NRC notes that it has judged and

continues to judge the safety of older plants on an

ad hoc and plant-specific basis (e.g., through the

Systematic Evaluation Program) rather than against

standardized design requirements, and finds that

adequate safety currently exists.

B Institutional Efforts Determining the

Adequate Safety of Aging Management

To assure the adequate protection of public

health and safety in the use of nuclear power, the

NRC performs a variety of regulatory activities to

address aging and other issues under the Atomic

Energy Act of 1954 as amended (AEA).9 Each

nuclear power plant has a unique set of NRC

requirements established at initial licensing and

modified over time to provide, in the judgment of

the NRC, a reasonable assurance of adequate

safety (box l-D). This set of requirements is

called the plant’s current licensing basis (CLB).10

Although the NRC plays a major role in assuring

nuclear plant safety, the AEA assigns the primary

responsibility for safe operation of a commercial

nuclear plant not to the NRC but to the plant

operator, or licensee .11 Each licensee is ultimately

responsible for the design, operation, and maintenance of its plant, not merely to meet NRC

requirements, but to assure safety.

Given the complexity and often plant-specific

nature of many technical issues, there are often

differing opinions, not only about technical isT Nuclear plants are designed with the principle of ‘defense in dept&’ involving redundancy and multiple safety systems to mitigate the

effects of any single failure. Thus, an accident involves a sequence of failures. One example of redundancy is in electrical supplies for critical

safety systems, which include offsite electricity sources, emergency diesel generators, and alternate supplies such as emergency batteries.

Another example is the multiple barriers designed to contain radioactive materials at successive locations, including the fuel matrix, fiel

cladding, primary coolant circuit boundary, and the containment structure. Age-related degradation in the SSCS can affect each level of defense

in depth to varying degrees.

a See, e.g., Diane Currtq counsel for the Union of Concerned Scientists, Hean”ngs B@ore the Subcommittee on Energy andthe Environment

of the Committee on Inten”or and Insular Affairs, House of Representatives, Nov. 5, 1991, pp. 93-95.

9 Atomic &er~ ~t of 1954 ~ amended (Am), fibfic Law 83-703,68 Sht. 919. ‘The NRC was esmbtished by the Energy Reorganization

Act of 1974 as an independent agency of the Federal Government. 42 United States Code Sec. 5841 et seq. Its regulatory responsibilities were

transferred from the U.S. Atomic Energy Commission.

10 ~s ~ge ~dy of rqu~ement~ is con~ed ~ a pl~t’s operating lice~e application or safe~ MysisRepo~ pklt SpeCflC COfIlp~ktlCe

with Commission regulations noted in 10 CFR Part 50, as well as other parts of Title 10 of the Code of Federal Regulations; Commission orders,

license conditions, exemptions and technical specifications; and all written commitments made by the licensee in docketed responses to NRC

bulletins and generic letters.

1142 U.,S.C. 2011 et seq.
12 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Box 1-D-How Safe Is Safe Enough?

An underlying question in determining the adequacy of aging management is the overall goal for nuclear plant

safety: “How safe is safe enough?” Absolute protection, that is, the total absence of risk, is neither possible nor

a meaningful goal for nuclear power plants or any other energy source. The Atomic Energy Act provides little

direction in answering the question of how safe is safe enough. Rather, it leaves that responsibility with the NRC

under the general charge of assuring adequate protection of the public health and safety.

To address the issue of acceptable risk to the public, the NRC formally set qualitative safety goals for nuclear

power plant operation in 1986, after several years of development, as well as quantitative objectives to be used

in determining achievement of the goals.1 For example, the policy states,

The risk to an average individual in the vicinity of a nuclear power plant of prompt fatalities that might

result from reactor accidents should not exceed one-tenth of one percent (0.1 percent) of the sum of

prompt fatality risks resulting from other accidents to which members of the U.S. population are

generally exposed.

The best available information indicates that, if aging is properly managed, the risk of fatalities resulting from

nuclear power plant operations in the United States is low relative to NRC’s safety objectives.

Although the safety goal policy can provide useful guidance in regulatory activities, it has some notable

limitations, perhaps the greatest of which is the practical difficulty of translating the risk-based goals into regulatory

practices. There is, however, a growing use of risk-based approaches, for example, in complying with the

maintenance rule.2 Other areas for potential improvement in the safety goal policy include: clarifying consistency

with safety goals in other Federal law; establishing a practical correlation with risks of non-nuclear electricity

resources; considerating changing demographic characteristics near a plant more fully; discussing the appropriate

use of cost-benefit analyses; and more explicitly treating the uncertainty inherent in risk estimation.

1 U.S. Nuciear Regulatory Comrnisdon, 51 Fix&@ l?eglster30028 et w., Aug. 21, 1938. ~ might*

expected, the NRC’s safety goals do not vary according to a plant’s age.

2 See, e.g., U.S. Nuclear Regulatory Commission, Regulatory Wide 1.160, Juns 1993; and Yankee Atomic

Eiectric Co., A@kaf/ons of FWA, EPRi NP-7315 (Paio Aito, CA: Eiectric Power Research Institute, May 1991).

sues, but about the appropriate level of technical assuring that operation of nuclear power plants

detail to consider in the regulatory process. In will not pose an undue risk to the public health

fact, many in the industry maintain that some and safety.”12 Some observers suggest that the

NRC activities and requirements are unpredicta- regulatory process itself, including the role of the

ble, costly, and unnecessary to assure an adequate courts, is overly cumbersome, legalistic, and

level of public health and safety. Similarly, some exacerbates uncertainty.13 Others suggest that

nuclear critics maintain that at least some NRC NRC policies have been too restrictive of public

activities are ‘‘contrary to Congress’ purpose of input in addressing important safety issues.14

12 me Ufion of Concerned scien~~ and the New England Coalition on Nuclear PollutioxL testimony on the FYoposed License Renewal

Rule for Nuclear Power Plants at hearings before the House Subcommittee on Energy and the Environment of the Committee on Interior and

Insular Affairs, Nov. 5, 1991.

13 M. W. Golay, “How Prometheus Came to be Bound: Nuclear Regulation in Americ&” Technology Review, June/July 1980, pp. 29-39.

Although the article was written some time ago, most of it remains pertinent today. Michael Golay, personal cmnrnunicatioq January 1993.

14 M. A&to, me union of con~rned Scientists, safety Second: The NRC andAmerica’s Nuclear Power Plants(hMhIMpds,m: hdhii

University Press, 1987). As one example, under 10 CFR 2.206, while the public may petition the NRC staff to initiate a proceeding, there are

no provisions for appealing staff decisions either to the Commission or judicially. However, the Commission has in the past invoked at its

discretion the power to review staff decisions upon receiving a petition from apubl.ic interest group. See U.S. Nuclear Regulatory Commission

‘‘In the Matter of Yankee Atomic Electric Company, “ Memorandum and Order, 50.029, July 31, 1991.
Chapter 1–Overview and Policy Issues I 13

Ultimately, although regulatory activities and

industry practices for managing aging (and other

safety-related issues) are based on detailed technical analyses, the determination of whether those

practices provide adequate safety lies with the

professional judgment of the NRC. In performing

its task, the NRC is often aided by other parties

including the nuclear industry, public interest

groups, and State agencies. The industry established the Nuclear Management and Resources

Council (NUMARC) in 1987 to coordinate interactions with the NRC on industry-wide regulatory

issues. The NRC’s process of issuing licenses and

developing new rules and regulations is largely

open, and public input is allowed, as required by

the Administrative Procedures Act.15 There have

also been numerous cases of judicial review of

NRC licensing and procedural decisions brought

by the public and interest groups.

It should be noted that while the NRC and the

commercial nuclear power industry have elaborate processes for addressing safety issues including aging, those processes have generally, but not

always, performed as effectively as intended. The

apparent failure of regulatory and industry processes with regard to the widely used fire retardant

Thermo-Lag provides one example outside the

area of aging. 16 However, such a failure appears

the rare exception.

There are several aging-related examples of

regulatory issues for which differing opinions and

questions about the appropriate level of technical

detail are yet to be resolved. Among them are

regulatory activities addressing steam generator

microflaws and RPV embrittlement, issues that

contributed to recent early retirement decisions at

two plants. The owners of the plants, both of

whom believed their plants to be safe, opted for

retirement, citing in part the uncertain but high

costs of meeting NRC requirements that were yet

to be determined (see descriptions of the Yankee

Rowe and Trojan retirement decisions in box

l-A.) Another major regulatory issue related to

aging for which implementation and other issues

remain to be resolved is license renewal, discussed below.

9 Aging Safety and License Renewal

As specified in the AEA, commercial nuclear

plant operating licenses may not exceed 40 years,

but may be renewed on expiration.17 The fried

term was established in the AEA for financial and

other nontechnical reasons, although once chosen, it became an assumption in specifying certain

plant design features (e.g., the number of thermal

cycles occurring, and thus the requirements for

fatigue).

During the past few years, the NRC and the

commercial nuclear power industry, with funding

support from the U.S. Department of Energy

(DOE), have devoted considerable effort to the

topic of nuclear plant license renewal. Although

the NRC promulgated its license renewal rule in

1991, 18 it will be several years before practical

implementation guidance is finalized. The NRC’s

implementation effort includes developing a‘ Regulatory Guide, ’ that instructs applicants in detail

on the standard format for technical information,

and a‘ ‘Standard Review Plan, ’ that instructs the

NRC staff in detail on the framework for reviewIS 5 U.S .c, sec. 55 I et seq. ‘‘Subchapter ~—~“ “strative Procedures. ’

16 AS ~wly as abut 1() ~ws ago when ~emo.~g was ~fified as a f~e re~d~~ several licensees raised concerns about the Illaterid’S

effectiveness with the NRC. However, the NRC did not act to exarnin e those concerns until the early 1990s, by which time about 84 plants

were using Thermo-Lag. Recently, the NRC Inspector General issued a report critical of the NRC’s performan ce in that case, and a grand jury

investigation has been initiated by the U.S. Attorney in Maryland.

17 Of tie ~~er cou~es wl~ lwge nucleti power pro~as, none ~ve adopted fix~ lice~e tc~s, The absence of fixed license terms is

one of a number of features that distinguishes U.S. nuclear regulatory practices from the international community. Organization for Economic

Co-Operation and Development, Nuclear Energy Agency, Licensing Systems and Inspection of Nuclear InsfalZations 1991 (Paris, France:

OECD 1991).

IS 56 Federal Register 64943-64980 (Dec. 13, 1991).
14 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Virginia Power replaced the steam generators at its

Surry units 1 and 2 (shown here) in 1979 and 1981,

respectively. Virginia Power attributes the relatively

low cost and rapid completion of the 1993 steam

generator replacement at its North Anna unit one in

part to the experience gained at Surry.

ing an application. Both of these efforts remain in

draft stages, which the NRC expects to finalize

after gaining experience from the first few applicants or, “lead plants,” working through the

process. The NRC has also proposed but not

finalized a rule establishing requirements for the

environmental review of license renewal applications, as required by the National Environmental

Policy Act.19 Even after the NRC acts on the early

license renewal applications, there may be court

challenges to the implementation of the rule that

would take additional time to resolve.

The inexperience with license renewal regulations is largely explained by the industry’s

relative youth-with the exception of one small

unit, the license of the oldest operating plant will

not expire until 2007 (table l-B). Although the

licenses of several other younger plants expire

sooner, a relatively simple NRC administrative

procedure allows those plants to extend their

expiration dates by the number of years spent

during construction.

20 By 2015, however, license

renewal would be required for continued operation of more than 40 other plants, over one-third

of those now in operation.

By the end of 1992, early license renewal

efforts at the two lead plants had been withdrawn

or deferred. Owners of the Yankee Rowe and the

Monticello plants originally planned to submit

license renewal requests in 1991 as part of a

jointly funded multiyear DOE/industry lead plant

program. However, Monticello’s owners indefinitely deferred their license renewal application

in late 1992 citing concern about the interpretation of the NRC’s rule, noting that the number of

systems to be reviewed had grown from the

original 74 to 104 with ‘‘no indication of where

it might go from there.’’21 Also noted as major

concerns were operational cost increases and lack

of resolution in spent fuel disposal. As noted in

box l-A, Yankee Rowe’s owners chose early

retirement in 1992 for economic reasons, including the cost of addressing NRC concerns about

1956Federal Register 47016.

~“ License terms were initially set based on the start of plant construction rather than the start of operation. However, NRC regulations allow

a relatively simple procedure to recover the construction period and thereby extend expiration of the initial operating licenses without license

renewal. The difference can be substantial. For example, the license for Unit 1 of the Diablo Canyon plant expires in 200S based on approval

of its construction license in 1968, although operation did not begin until 1984 following a series of construction delays. By recovering the

construction period in the initial license, Diablo Canyon would require license renewal only in 2024, 16 years beyond the current expiration.

For this reasou the year of expiration as currently shown for some licenses is not an accurate reflection of the date at which license renewal

would be needed.

21 J How~d, Chief Executive Officer of Nofiem States power, cit~ k “Lice~e Renew~ Suffem New B1OW tis NSP Application is

‘Deferred’, ’’Nuc/eonics Week, vol 33., No. 46, Nov. 12, 1992, pp. 1, 12, 13. The actual systems to be reviewed are not specitled in the license

r~new~ role, ~d the NRC neither determined nor reviewed NSP’S lists of 74 and 104 systems. That is, the actual number of systems to be

reviewed remained uncertain at the time NSP deferred its license renewal effort. See also, Northern States Power Co., “Perspectives on the

License Renewal Process,” Nov. 20, 1992.
Chapter 1–Overview and Policy Issues 15

Table 1-B—U.S. Commercial Nuclear Power Operating License Expirations Through 2015

Yeara

(Assuming Year (Under current

construction recapture) license, if different) Name Generating capacity (MW)

2011

2012

2013

2014

2007

2007

2008

2007

2008

2008

2008

2002 2000 Big Rock Point

2007 2007 Haddam Neck

2009 2004 Oyster Creek 1

2006 Dresden 2

Ginna

Nine Mile Point 1

2010 H.B. Robinson

Millstone 1

Monticello

Point Beach 1

Palisades

Dresden 3

Turkey Point 3

Maine Yankee

Pilgrim 1

Quad Cities 1

Quad Cities 2

Surry 1

Vermont Yankee

Turkey Point 4

Peach Bottom 2

Fort Calhoun

Indian Point 2

Kewaunee

Oconee 1

Oconee 2

Point Beach 2

Prairie Island 1

Surry 2

Zion 1

Zion 2

Peach Bottom 3

Arkansas Nuclear 1

Browns Ferry 2

Brunswick 2

Calvert Cliffs 1

Cooper

D.C. Cook 1

Duane Arnold

Edwin 1. Hatch 1

Fitzpatrick

Oconee 3

Prairie Island 2

Three Mile Island 1

2015 2009 Indian Point 3

Millstone 2

67

560

610

772

470

615

683

654

536

485

730

773

666

860

670

769

769

781

504

666

1055

478

939

511

846

846

485

503

781

1040

1040

1035

836

1065

754

825

764

1020

515

741

780

846

500

808

965

863

a Year of expiration assuming that the maximum number of years for construction recapture has been added to the current

expiration date (i.e., 40 years from start of plant operation).

SOURCE: U.S. Nuclear Regulatory Commission, kr~ormation Digest 1992 cd., NUREG-1350 (Washington, DC: March 1992)

pp. 48, 79-91.
16 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

the metallurgical status of the RPV during its

review of the plant’s license renewal efforts.

In late 1992, a group of five utilities operating

seven plants designed by Babcock and Wilcox

(the Babcock and Wilcox Owners’ Group, BWOG),

announced its intentions to pursue a joint effort in

developing a license renewal application. Because there are several utilities and power plants

represented by the BWOG, costs and experiences

of preparing the license renewal applications can

be shared, improving the prospects for a successful application. However, the group does not

expect to select a plant and submit an application

until 1997. Other owners’ groups are developing

similar programs.

In December 1992, a senior NRC staff management group undertook a review of license renewal

issues at the request of the Commission and

proposed a revised implementation approach. The

staff review concluded that the rule does not need

to be changed, and that an efficient process can be

implemented. Despite the favorable NRC staff

review, however, there still appear to be some

problems and uncertainties with the rule and

questions about its practical implementation,

which are discussed below. The NRC is continuing to address these issues including holding a

public workshop.22

As promulgated in 1991, the license renewal

rule and the accompanying statement of considerations (SOC) appear somewhat inconsistent with

other NRC aging efforts. The license renewal rule

and SOC require renewal applicants to perform a

formal, and potentially far more detailed, demonstration that aging issues are addressed than

otherwise applies to existing plants as they age. In

particular, the rule and SOC require utilities to

perform and file with the NRC for approval an

integrated plant assessment (IPA). As described

in the SOC, the IPA includes a detailed evaluation

of aging degradation for all SSCs directly or

indirectly affecting safety. Depending on the

level of detail required, this evaluation could be

a difficult and costly undertaking. An NRC study

estimated the cost to be about $30 million per

plant. 23 In contrast, no other NRC regulations

require such a formal, detailed evaluation of

aging. The recently proposed staff implementation approach would largely bypass this step.

Although perhaps appropriate for assuring adequate safety, that staff interpretation strays from

the rule’s SOC and could expose renewal applications to court challenges.24

The rule further requires that licensees obtain

regulatory approval of ‘‘effective programs’ to

address any ‘‘age-related degradation unique to

license renewal” (ARDUTLR) that could occur.

In contrast, the NRC’s maintenance rule, while

requiring utilities to have effective maintenance

programs, does not require formal regulatory

filing and approval of the detailed programs.

Further, while the license renewal rule requires

that an effective program must maintain the

plant’s CLB, the maintenance rule allows other

objectives, for example, based on risk-significance.

Beyond some inconsistency with other NRC

aging requirements, there are other potential

problems with the license renewal rule and its

eventual implementation. For example, the concept of ARDUTLR as used in the license renewal

rule is less useful than it first appears. Although

apparently intended to limit the scope of detailed

aging examinations and effective programs to

22 u.S. Nuclear Regulatory Commission “Additional Implementation Information for 10 (2FR Part 54,” “Requirements for Renewal of

Operating Licenses for Nuclea Power Plants,” “ SECY-93-1 13, Apr. 30, 1993; and U.S. Nuclear Regulatory Commission, “Implementation

of 10 CFR Part 54, ‘Requirements for Renewal of Operating Licenses for Nuclear Power Plants, ’ SECY-93-049, Mar. 1, 1993; and 58 Federal

Register 42987.

23 U.S. Nuclm Re@ato~ Comrnissioq Regulatory Analysis for Final Rule on Nuclear Power Plant License Renewal, NUREG-1362

(Washington DC: October 1991), table 4.6.

x Mem~~d~ ~om Willim C. paler, Gener~ Counsel, to the U.S. Nuclear Regulatory Commission “License Renew~ ~d SECY

93-049,” Mar. 9, 1993, Pp. 4,5.
Chapter 1–Overview and Policy Issues I 17

issues not already explicitly addressed in the

original license term, according to the NRC staff,

there are few if any SSCs that can be readily

shown to have no ARDUTLR as defined in the

rule. For example, it is difficult to show that even

relatively short-lived SSCs under a regular refurbishment or replacement program have no ARDUTLR according to the NRC staff. Regarding

long-lived, or life-of-plant SSCs (e.g., containment structures and RPVs), there is little expectation that new aging mechanisms will occur only

beyond the original license term. Instead, the rates

of degradation and the safety implications are not

precisely known, so aging management involves

a continuing effort of maintenance and of evaluating operating experience and research.

I Federal Policy Considerations; Assuring

Adequate Aging Safety

The Federal Government’s main responsibility

in relation to nuclear power plants is assuring

adequate protection of the public health and

safety-a responsibility charged primarily to the

NRC. Current regulatory and industry efforts to

address aging are designed to provide a reasonable assurance of adequate safety. However, there

are some aging issues in the safety regulatory

process with longer term implications that may

benefit from early attention. The safety policy

options listed in table 1-A would not necessarily

provide for a greater level of safety-rather they

could more quickly identify and resolve concerns

likely to arise as aging issues continue to be

addressed in the coming years, reducing regulatory uncertainty and allowing more timely decision making by the NRC and the industry.

The first two policy options listed specifically

address aging issues. The latter two may be

important not only for aging but for the broader

array of safety regulation as well.

1. Accelerate Ongoing Aging-Related Safety

Activities.

Early license renewal efforts suggest that the

NRC’s existing aging-related safety efforts could

be accelerated. According to the NRC staff, early

license renewal efforts helped focus needed

attention on two aging issues that are of generic

importance to the industry during the original

license terms of existing plants--EQ and fatigue.

The NRC staff has suggested treating both topics

as Generic Safety Issues (GSIs), resulting in a

more detailed regulatory re-ex amination for

plants during their current licensed lives. Early

license renewal activities at one lead plant (Yankee Rowe) also brought additional attention to a

third topic of importance to a smaller number of

plants, RPV embrittlement.

That license renewal activities brought this

additional attention should not be surprising,

since the rule places greater importance on

formally identifying and managing aging degradation than is required for plants not seeking

license renewal. However, any dependence on

license renewal activities to address aging challenges that occur during original license terms

may be a perverse allocation of efforts, since the

plants most affected by aging degradation may

also be those least likely to seek license renewal.

Such a dependence also leaves unclear how and

at what point such focus will be brought absent

future license renewal applications.

To help ensure that other aging issues, whether

generic or plant-specific, are focused on in a

timely fashion absent detailed license renewal

efforts, the NRC could pursue a variety of efforts.

For example, the NRC could accelerate and

intensify the review of topics raised by industry

and NRC aging research programs for application

to regulatory activities. This could go a long way

to supplanting dependence on license renewal

activities to identify aging issues needing additional attention. For example, none of the three

topics raised in the license renewal activities

noted above were new to industry or to the NRC,

having been identified previously in research
18 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

programs. In this review, the NRC could also

consider the appropriate level of effort applied to

aging in long-lived SSCs versus shorter lived,

regularly refurbished or replaced SSCs.

Second, as utilities finalize compliance with

the maintenance rule over the next 3 years, the

NRC could monitor and report on whether the

relatively flexible approach (i.e., without formal

filing and regulatory approval of plant-specific

maintenance programs, and without an equivalent

of the plant-specific integrated plant assessment

as originally envisioned for the license renewal

rule) adequately identifies and addresses aging

degradation. In particular, in reviewing maintenance rule compliance and adequacy, the NRC

could assess whether the level of technical detail

and analysis of aging issues provided by an IPA

(as described in the preamble to the license

renewal rule) would provide a substantially greater

assurance that aging issues are being identified

and addressed in a systematic fashion.

2. Simplify the License Renewal Rule.

If ongoing aging management programs are

adequate during an original license term, it may

be possible to considerably simplify the license

renewal rule without affecting safety. The recent

NRC staff proposals for implementing the current

license renewal rule include several simplifications. However, the staff interpretations allowing

for the simplifications are not entirely consistent

with the rule’s preamble and may thus be subject

to considerable regulatory and court challenge.

For this reason, the NRC staff has proposed

consideration of an additional rulemaking to

revise the current rule.

In reopening the license renewal rule, it may be

worthwhile for the NRC to consider further

simplifications in the rule than those contained in

the staff proposal. For example, with adequate,

ongoing aging management, it may be appropriate to treat license renewal as a relatively simple

administrative procedure. One principal justification for the license renewal rule as promulgated in

1991 is the need to address aging degradation

issues that arise during a plant’s license renewal

term but not in the current license term. However,

the practical distinction between ARDUTLR and

aging generally is hazy and artificial for both

short-and long-lived SSCs. Even for long-lived

SSCs, aging management in a current license

term may involve revalidation of previous analyses of aging degradation rates and design margins

as more operating experience and research are

gained. For this reason, it may be better to view

aging management as a more continuous process

than established in the license renewal rule.

Even assuming the premise that some aging

degradation is best viewed as unique to license

renewal, it may still be appropriate to simplify the

license renewal rule for greater consistency with

other NRC aging requirements. Two revisions

suggested in the recent NRC staff proposals are:

more explicit approval of the use of the maintenance programs required under the maintenance

rule; and redefining ARDUTLR in such a way

that it focuses on long-lived SSCs and not on

short-lived SSCs that are replaced on a time or

performance basis.

One potential concern with simplifying license

renewal requirements is that it may allow a

severely degraded nuclear plant to continue

operating beyond its original license term. However, the risk that a simplified license renewal rule

would allow should be minimal if other aging

management practices are adequate. The two

earliest license expirations are set for 2002 and

2007. Any inadequacies in current and planned

aging management practices need to be corrected

before current licenses expire, rather than relying

on license renewal requirements and the ambiguous concept of ARDUTLR.

One consideration in revising the license renewal rule could be whether the estimated $30

million cost per applicant of producing a detailed

IPA is the most productive use of funds for

addressing aging issues. It may be more productive to devote resources to addressing aging

issues affecting plants in their current license

terms, or even to safety issues not directly related
Chapter 1–Overview and Policy Issues I 19

to aging. For example, both human and containment structure performance in existing plants

continues to receive NRC and industry attention,

and remain sources of uncertainty in safety

assessments.

3. Revise Public Participation Provisions

The NRC’s regulatory process is largely open,

and public participation is allowed. However, by

virtue of being a licensing proceeding, the license

renewal process for any plant will allow a

considerably more extensive public role in examining aging issues than provided during the

current license term under existing law. For those

doubtful of the adequacy of industry and NRC

safety efforts, license renewal will allow an

important opportunity to challenge licenses both

in the NRC hearing process, and quite possibly

through the courts.

To the extent that a greater public role at the

time of license renewal would help provide a

better assurance of adequate safety with respect to

aging, it may be worth examin ing how that

benefit could be gained more generally during a

current license term and not linked to a specific

regulatory action. In the past, public participation

has focused NRC attention on aging safety issues

leading to license modifications. 25 Revising some

public participation provisions may also help

alleviate public concerns about safety.

In particular, under NRC regulations,26 the

public may petition the NRC staff to initiate a

proceeding, but there are no provisions for

appealing staff decisions either to the Commission or judicially. 27 One approach that has been

suggested is to allow judicial review of public

petitions to initiate a proceeding to modify,

suspend, or revoke a license.28 A central issue in

considering this approach is whether the likely

benefits warrant the additional burdens on the

court system, the utilities, and the NRC that

allowing such review could bring.

An alternate approach that could potentially

avoid the cumbersome and confrontational nature

of formal hearings is to consider involving critics

of the industry and others earlier and more

directly in the regulatory process. Providing for

more ongoing public participation may also help

reduce the uncertainties arising from challenges

in the NRC hearing process and the courts. In the

past year, noting a longstanding criticism by

citizens’ groups and some members of Congress

with regard to NRC’s public petition process,

NRC has undertaken an effort, including holding

a public workshop, to examine possible revisions

to its procedures for treating public petitions.29

The NRC’s enhanced participatory process for

establishing site release criteria for decommissioning is one example of a current effort that may

be worth expanding to other regulatory areas.

Among the approaches that others have suggested

include drawing from a broader cross-section of

interested and technically competent parties for

NRC advisory positions (e.g., the Advisory ComZS See, e.g., Ution of concerned scientists and the New England Coalition on Nuclear Pollution ‘‘Petition for Emergency E~omement

Action and Request for Public Hearing, ’ before the U.S. Nuclear Regulatory Comrnissio~ June 4, 1991. The aging degradation issue raised

in the petition (the effect of embrittlement on the integrity of one plant’s RPV) had been previously identifkd by the NRC staff and was under

continued investigation. However, the Chairman of the NRC noted that the petition stimulated the Commission’s thorough review of the

analyses leading to an NRC order. U.S. Nuclear Regulatory Commission, “In the Matter of Yankee Atomic Electric Company, ’ Memorandum

and Order, 50.029, July 31, 1991; and Statement of Ivan Seli.n, ChairrmQ U.S. NRC, before the House Subcommittee on Energy and the

Environment of the Committee on Interior and Insular Affairs, Aug. 1, 1991.

2610 C7R 2,20(5

27 However, he Co~5510n ~~ the past ~voked, at i~ discretion, he power to ~view st~ decisions upon rmt3iVkIg ii petitiOIl flOUl

a public interest group. U.S. Nuclear Regulatory Commission, ‘‘In the Matter of Yankee Atomic Electric Company, ’ Memorandum and Order,

50.029, July 31, 1991.

28 Exmples ofleg151ative pmps~5t. eme the5e res~ctiomwe fo~d ~ S. 1165, 103d Conwess; ~d U.S. House of Representatives Rept.

102474 Part 8, Report on the Comprehensive National Energy Policy Act, Title I Subtitle C, May 5, 1992.

29 See Federal Register 34726 (June 29, 1993).
20 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

mittee on Reactor Safeguards), and some form of

intervener funding could be used (e.g., to retain

industry critics to review and comment on specific aging-related topics) .30 Some in the industry

may object strongly to any requirements to fund

critics, either directly or through their NRC fees.

However, similar options are used to some degree

in various regulatory activities of different States.

For example, integrated resource planning efforts

performed by States and utilities have increasingly involved participation by the public, consumers, and competing generators in part to

lessen the contentiousness of adversarial proceedings. As an example of a broadly based advisory

group, the Pennsylvania State Low-Level Waste

Advisory Commission specifically includes a

wide range of members, including local government, environmental, health, engineering, business, academic, and public interest groups.31

4. Apply the NRC’s Safety Goal Policy to Aging

Issues.

While the NRC’s aging-related regulatory activities are elaborate, the relationship between

those activities and the NRC’s safety goals (box

l-D) could be made more clear. For example, the

safety goal policy is not mentioned in the license

renewal rule, the 32-page Statement of Considerations accompanying the rule,32 or the NRC’s

regulatory analysis of the rule.33 Similarly, the

NRC’s most recent plan for its Nuclear Plant

Aging Research (NPAR) program does not reference the safety goal policy statement in its

approximately 170 pages.34 The NRC has had an

ongoing effort to make greater application of the

safety goal policy.

35 As part of that effort, the

NRC could undertake a more visible and comprehensive effort to ensure that its safety goal policy

is appropriately translated into regulatory and

research activities related to aging. Further, although a good step forward when it was produced

in 1986, the policy itself has some limitations and

has not been revised despite considerable advances in the state of the art of risk assessment.

Several of the limitations relate to plant aging

issues. The NRC could revisit its safety goal

policy to ensure that it provides as meaningful a

basis as possible for NRC regulatory actions for

existing plants.

ECONOMY OF EXISTING PLANTS

The economic prospects for existing nuclear

power plants depend not only on the reliability

and costs of individual plants but also on the

broader economic context of the electric power

industry. Uncertainty and change are hallmarks of

the electric power industry. Several electric industry trends diminish the long-term economic

prospects for existing nuclear plants including:

rapid growth in utility industry restructuring and

supply competition; low load growth, often resulting in excess capacity; growing utility efforts

to tap into a large, low-cost potential for improved

energy efficiency; and continuing high availability and low prices for natural gas for electricity

generation. At least one trend, incorporating

environmental externalities, may improve the

prospects, however. In particular, concern over

30 see, for ~xwple, U.S. conge~~,offIce of ~c~olo~ Assessm~t, Nuc/eur power in un Age Of uncertainty, OTA-E-216 (Washington

DC: U.S. Government Printing OffIce, February 1984), p. 260; and John Kemeny et al., Reporr of the President’s Com”ssion on the Accident

at Three Mile Island (Washington DC, 1979).

sl ~w~ of pennsyh~, ~t 1988-2} “An Act providing for low-level radioactive waste dispo@” Section 317.

3256 Federa[Register 64943-64980 (llx. 13, 1991).

33 U.S. NUCIW Re@atory co~ssloq Re8ulato~ Analysis for Final Rule On Nuclear power plant License Renewal, NUREG-1362

(Washington DC: October 1991).

34 u.S. Nu~le~ Re@atory co~ssion Nuclear P/anrAging Research (NP~) Program plan, NUREG-1 144 Rev. 2, (WdI@tOn, DC:

June 1991).

35 u.S. Nuclear Regulatory COmIniSSiOn+ “Interim Guidance on Staff Implementation of the Commission’s Safety Goal Policy,

SECY-91-270.
Chapter 1–Overview and Policy Issues 21

global climate change and other environmental

challenges related to fossil fuel combustion, if

factored into economic analyses, could improve

the relative economics of existing nuclear plants

considerably (box l-E). Increasingly, these factors are being examined through what are often

elaborate planning exercises, called integrated

resource planning (IRP).36

In addition to change, there is great diversity in

electricity market conditions and the value of

nuclear power across the country. For example,

because excess capacity and fuel costs vary by

region, current estimated replacement costs for

power are far lower in some areas than in others.

Similarly, existing units provided 22 percent of

U.S. electricity in 1991, but some regions of the

country, primarily along the Atlantic seaboard

and parts of the Midwest, are far more dependent

on nuclear power (figure 1-1).

All power plants, nuclear and non-nuclear, will

eventually be retired. But at what point does it

make sense to retire a plant, and what unique

issues are raised by nuclear plants? Aging effects

on plant economic performance can be important

factors affecting the economic attractiveness of

existing plants .37 However, other factors can play

an equal or greater role in determiningg a plant’s

economic performance, such as the cost and

availability of waste disposa138 (box l-F) and the

cost of addressing safety issues not related to

aging. Decommissioning costs can also be a

factor in plant life decisions. For example, one

effect of delaying plant retirement is to defer

decommissioning, which may be an economic

benefit or a burden depending on future cost

escalation. Also, delaying plant retirement can

allow spreading decommissioning costs over a

greater sales volume.

Opinions of the long-term economic prospects

for existing nuclear power plants vary greatly.

DOE-sponsored studies have estimated that the

economic gain from extending operation an

additional 20 years could be about $350 billion

nationally. 39 Those results are disputed by some

who find that nuclear power costs are high and

expect they will continue to grow.40 Some analysts suggest that as many as 25 plants, not

necessarily older ones, may be found uneconomic

during the next several years.41 Certainly, the

growing number of recent early retirements, and

others currently being investigated, is an indication that prospects are not as economically

attractive as thought even as recently as 1992

when an update to the 1991 the National Energy

Strategy was published.42 Still, costs and other

economic conditions vary widely among nuclear

36 See U.S. Conuess, OffIce of Technology Assessment, Energy Eficiency: Challenges and Oppo~nities for Electn”c Ufiiities, to be

published.

37 AS used here, plant economic performan ce is a combination of the operational costs of a plant, the costs of major refurbishment and other

capital additions, and the reliability and output of the plant.

38 Dispos~ of ~th spent fiel ~d low.level waste ~w) can pr~ent ~ono~c c~eng~. Howev~, LLW volumes d- plant Opemtion

are small, and current disposal costs represent a fraction of one percent of the operational costs of current nuclear plants, Even with the much

higher disposal costs anticipated under the interstate compacts, LLW costs will average only about 1 percent of operational costs, The large

volumes of LLW resulting from decommissioning, however, present much greater costs relative to that activity, and are discussed below in

that context.

39 L. Malcovich, L. Forest, and T. Fletcher, “U.S. National and Regional Impacts of Nuclear Plant Life Extensiou” Sandia National

Laboratories, SAND87-7136, Januasy 1988.

m See, e.g., James G. Hewle~t ‘‘The Operating Costs and Longevity of Nucleas Power Plants,’ Energy Policy, July 1992, pp. 608-622.

41 p.c. pwstiey, D.F. Grosser, and D.A. Roule~ Shearson Lehman Brothers, “Should Investors Be Concerned About Rising Nuclear Plant

Decommissioning Costs?,” Electric Utilities Commentary, vol. 3, No. 1, Jan. 6, 1993, p. 1.

42 me discussion of efis~g nucl= ~wer plams in the National Energy Strategy repO~ tid not ac~owledge tie ProsP@ ‘f ‘$’

retirements. Rather, it emphasized the prospects for license renewal for about two-thirds of existing units. U.S. Department of Energy, National

Energy Srrategy: Powerjid Zdeasfor Americu One Year Later (Washingto~ DC: February 1992), pp. 32-36; and U.S. Department of Energy,

National Energy Strategy (Washington DC: February 1991), pp. 108-116.
22 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Box 1-E–Existing Nuclear Power Plants and Global Climate Change

The potential for global climate change, a growing environmental concern, clouds the long-term prospect for

the continued, heavy international reliance on fossil fuels. The public health and environmental harm that some

suggest are likely results of climate change maybe far more severe than even pessimistic assumptions of nuclear

accidents. While the operation of existing nuclear power plants does not solve the CO2 problem (a key greenhouse

gas), existing nuclear units help act as a bridge to other nonfossil options including greatly improved energy

efficiency, advanced nuclear generation, and renewable supplies. For example, if the 613 billion kWh of electricity

produced using nuclear power in 19911 had instead been fueled by coal, U.S. CO2 emissions would have been

higher by about 160 million metric tons, over 10 percent of energy sector emissions that year.2 Similarly, if fueled

by natural gas in highly efficient combined cycle units, emissions would have been higher by about 70 million metric

tons.

Federal and State environmental policy addressing global climate change could greatly improve the relative

economic attractiveness of existing nuclear power plants.3 An increasing number of States are considering

environmental and other externalities in new least-cost planning or integrated resource planning efforts.4 in April,

the President announced a commitment to stabilize greenhouse gas emissions at 1990 levels by the year 2000.

What future efforts will be taken to meet that objective is yet to be determined.

Although there are no plans to institute a tax on carbon emissions, the potential impact on relative economics

are illustrative. For example, consider a hypothetical $100 per ton carbon tax, which one Congressional Budget

Office study estimated could potentially reduce U.S. CO2 emissions by between zero and 25 percent from then

current levels over a 10-year periods Such a large tax would translate into nearly $0.03/kWh for coal-fired electric

generation, I?IOr8 than the average operational costs at existing nuclear power plants.

The environmental drawbacks of nuclear power are also widely noted. Safely storing, transporting, and

disposing nuclear wastes present environmental challenges. So too does the potential for a catastrophic nuclear

power plant accident, even though the probability of such an accident is very low. Overall, further examination of

the relative environmental impacts of producing electricity by fossil, nuclear, renewable, and other sources may

help ensure better informed and more timely decisions about the national energy mix and about individual plant

lives.

1 IJ.S. Depart-t of Energy, Energy Information Administration, Electdc FbWrA/V?ua/ 7991, DOaEIA0346(91) (Washington, DC: February 1993), p. 32.

2 Average C@ plant carbon emissions are about 0.56 to 0.59 pounds per kwh. Natural gaS @nemtiOn u~n9

combined cycle plants produces about 0.26 pounds per kwh. U.S. Congress, Offioe of Technology Assessment

Changing by Degrees: Steps to Reduoe Greenhouse Gases, OTA-O-462 (Washington, DC: U.S. Government

Printing Offioe, February 1991), p. 93

3 other resources, such as renewabie energy and energy effidenoy ~asureS,* not Produ~ C%

emissions and would aiso have improved economics. Natural gas and petroleunfired generation produce about half

the C02 per unit of electricity as does coat and could be affeoted as well. However, the dominant role of ooal, whioh

supplies 55 percent of the Nation’s electddty makes it Iikety that aggressive action to oontrol C02 emissions would

affect all aspects of the eleotridty market.

4 see U.S. Congress, office of Technology Assessment, ~~e~y Hfh3ency: Chdenges ati %ofiL@tks

for Electtic UtMtles, to be published.

5 u-s. Congress, congressional Budget offi~, @r&n Char@s as a Response fo @obd b4kW)’7h~: ~8

EffWts of Tiwdng Fossil Fuels (Washington, DC: U.S. Government Printing Offioe, August 1990).
Chapter 1–Overview and Policy Issues 23

Box 1-F--Spent Fuel Disposal

The Nuclear Waste Policy Act (NWPA) requires the DOE to begin accepting spent nuclear fuel from

commercial power reactors no later than January 31, 1998.1 DOE’s effort to characterize and potentially construct

a permanent spent fuel repository at Yucca Mountain, Nevada will be completed no sooner than 2010, under a

schedule viewed by many as optimistic.2 The DOE has also pursued the development of a monitored retrievable

storage (MRS) facility for the interim storage of spent fuel and other high-level waste by the year 1998 to meet

NWPA requirements.3 Serious doubts about whether the DOE could meet the 1998 MRS deadline4 were

substantiated by a December 1992 announcement that the DOE seeks to redirect its existing program substantially

by focusing on the development of Federal sites for interim storage.5

To cover the cost of disposal, utilities pay the DOE Nuclear Waste Fund (NWF) 0.1 cents for each

kilowatt-hour of electricity generated in nuclear power plants, an average of about $5 million annually per plant.

Of the $8 billion in utility fees and interest collected between 1983 and 1991,$3 billion has been spent6 with what

many have characterized as little progress. Whether the current fees are adequate, insufficient, or excessive to

cover actual disposal costs remains to be seen.

Limited on-site spent fuel storage capacity together with the lack of progress in DOE’s programs

undermines public confidence in a resolution tot he issue, and could threaten several operating plants with

premature closure in the next fifteen years. For example, Minnesota’s Northern States Power (NSP) operates

the twin Prairie Island plants having operating licenses expiring in 2011 and 2013, although current spent fuel

storage capacity is sufficient only through 1995. To address the shortfall, NSP proposed the installation of a dry

storage facility. Out of concern that the dry storage facility would become a de facto permanent repository,

however, the Minnesota Public Utilities Commission allowed NSP to construct a smaller facility that would add only

seven more years of storage capacity.7 Further, the facility must be approved by the State Legislature. If unable

to operate at the end of that time, this will represent a very large indirect cost of waste disposal.

Several utilities have dry storage facilities in operation or under construction. For example, the Public Service

Co. of Colorado (PSC), operator of the retired Fort St. Vrain plant, has constructed a dry storage facility for $23

million and estimates annual operational costs of about $1.5 million.8 The direct costs to utilities and their

customers are not large relative to total plant operational costs, but represent an unanticipated burden on utilities

and consumers that have paid for and expect a federally run geologic repository.

1 P.L. 97-425,96 Stat. 2258, Sec. 302(a) (5)(B)t

2 Nuclear Waste Technical Review Board, /VW7F?13 Special Report (Arlington, VA: March 1993, p. v.

3 U.S. Department of Energy, Office of Civilian Radioactive Waste Management, Report to congress on

Reassessment of the Civilian Radioactive Waste Management Program, DOEIRW-0247 (Washington, DC:

November 1989), pp. ix-x.

4 See u-s. Congress, General Amunting Office, Operation of Monitored Retrievable stora9e Faci/jtY /s

Unlike/y by 1998, GAO/RCED-91 -194 (Gaithersburg, MD: September 1991).

5 J-s D. Wawins, Secretary, U.S. Department of Energy, letter to J. B8nnett Johnston, Chahan, Senate

Committee on Energy and Natural Resources, Dec. 17, 1992, See attachment, p. 2.

6 Uts. DePartment~f Energy,finL@Repo~ttoCongress:~fi~of C/v///an R@oactive Waste hfanagement,

DOE/RW-0335P (Washington, DC: March 1992), pp. 54,65.

7 IINSp Gets Reprieve From Minnesota Psc,” me /%er&IY Dai/y, Vol. 20, No. 124, June 2% 1992* P. 10 ‘ee

also 57 federal Register 34319 (Aug. 4, 1992).

8 Mi~ael Niehoff, public Servim Co. of Coiorado, personal communi~tion, S@. 23, 1992.
24 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Figure 1-3—Nuclear Power Plant Production Costs

1970-1991 ($1991)

D Fuel

m Non-fuel /rhi’fr

1970 1974 1978 1982 1986 1990

SOURCE: Office of Technology Assessment, adapted from Nuclear

Engineering /ntemationa/, September 1992, p. 45; nominal dollars

adjusted using Consumer Pries Index.

plants appear attractive for the foreseeable future,

assuming costs are controlled.

Variability in the effectiveness of nuclear

utility management has long been recognized.43

Continuing evidence of variability can be seen in

the wide range of plant economic performance

and in the NRC’s systematic assessment of

licensee performance (SALP) program. The wide

range of performance indicates there are opportunities for improved economics at many plants.

Efforts to control rising operating and maintenance (O&M) costs include individual utility

programs and industry-wide initiatives to address

O&M costs by all nuclear utilities. The growing

awareness of the potential for early plant retirement and other economic performance incentives

may play an important role in motivating utilities

to take a variety of steps to reduce cost and

improve performance.

1 Aging Issues in Plant Life Economics

Real nonfuel (O&M) and fuel costs per unit of

electricity generated at nuclear power plants are

about triple their 1975 levels (figure 1-3). By

1989, average operational expenditures at U.S.

nuclear power plants were higher than for an

average coal plant for the first time.44 Dramatic

cost increases in the late 1970s and early 1980s,

however, were followed by declines in the late

1980s and early 1990s.45 While economic retirement decisions are based entirely on plantspecific factors rather than industry averages, the

general cost trends do indicate the nature of the

economic challenge for the industry. If operating

cost trends resume their long-term rate of increase, the operation of many existing nuclear

power plants will become less economically

attractive, possibly favoring early retirement even

where replacement capacity is needed.

Much of the historic growth in operating costs

was unrelated to plant aging. For example, the

experiences gained from the Browns Ferry accident in 1974 and the Three Mile Island accident

in 1979 led to costs for revising both equipment

and procedures. The rapid growth in average plant

staffing, a primary component of O&M costs,

does not appear to be age-related. The future rate

of cost escalation is speculative. Some future

O&M costs related to aging management could be

substantial. For example, the NRC estimated the

industry’s cost of implementing the maintenance

rule at over $1 billion (1990 dollars) .46 The NRC

further estimated that improved operational per4S See U.S. CoWess, OffIce of ‘lkchnology Assessment Nuclear Power in an Age of Uncertainty, OTA-E-216 (Wash@to~ DC: U.S.

Government Printing Ofllce, Februaq 1984), pp. 113-138.

44 US, ~p~ent of Energy, Energy ~omMtion AdndnistratioW Electric Plant Cost and Power Production Expenses 1989

DOE/EIA-0455(89), (wSShiIlgtO~ DC: March 1991).

45 U.S. Dep~ent of Energy, fiergy ~OrrnatiOn ~“ “stration (EI.A), An Analysis of Nuclear Power Plant Operating Costs: A 1991

Update, DOE/EIA-0547, (Washington, DC: May 28, 1991); and U.S. Department of Energy, EIA, Electn”c Plant Cost and Power Production

Expenses 1990, DOE/EIA-0455(90) (Wssbingtou DC: June 1992),

4656 Federal Register 31306 et seq., (JdY 10, 1991).
formance and availability would result in a saving

of just under $1 billion. The NRC’s cost estimates

were disputed by the industry, which asserted that

although the costs of regulatory compliance were

substantial, current maintenance practices were

already appropriate.

In addition to normal operational expenses,

many nuclear power plants have required substantial expenditures on capital additions for

major plant refurbishment. Although average

capital additions costs have declined from their

peak in the mid-1980s,47 many plants will continue

to need them. The types of capital additions

undertaken at nuclear power plants are varied,

Historically, some have been for NRC-required

safety backfits unrelated to aging such as fire and

seismic protection. However, many plants face

major capital additions costs related to aging

degradation. Steam generator replacements, performed at several plants already and under

consideration for many more, are a major example, costing $100 to $200 hundred million dollars

per plant. It should be noted that some capital

additions such as steam generator replacement,

while costly, should also improve plant performance. Depending on how the NRC resolves some

issues in the coming years, addressing agingdegradation such as EQ, fatigue, and RPV embrittlement may also involve major capital additions

for at least some plants.

The high costs and potential for extended

outages may effectively turn some major capital

additions decisions into plant life decisions. For

example, the prospect of large capital additions

requirements at two nuclear power plants (Trojan

and San Onofre) prompted economic analyses

that eventually led to early retirement decisions.

Several other plants facing steam generator replacements are also performing detailed economic analyses.

Because capital additions costs may be amortized over the life of a plant, license renewal can

Chapter 1--Overview and Policy Issues 25

m

t “j , “ JPJ!ii

—

The independent spent fuel storage installation (ISFSI)

for Baltimore Gas and Electric Company’s Calvert

Cliffs plants is one of several in operation or under

development. With delays anticipated in the Federal

Government’s opening of high-level waste facilities,

continued operation of many commercial nuclear

power plants may require development of ISFSIs.

affect plant life decisions even before license

expiration. For example, if a utility considers

license renewal, replacing a faulty steam generator (leading to a remaining life of 40 years or

more) may be more attractive economically than

shorter lived but less costly repairs such as

plugging or sleeving the steam generator tubes or,

as in the case of the Trojan plant, early retirement

based on the life of the current steam generators.

The importance of license renewal in economic

life decisions will grow as plants near the end of

their licenses. But again, only two plants, including one very small one, will require license

renewal for continued operation in the next 15

years.

I Institutional Roles in Deciding Economic

Plant Lives

Responsibility for the economic performance

of existing nuclear power plants lies with the

utilities operating them. However, the responsibility for economic decisions regarding nuclear

power plant lives, while lying primarily with the

41 U.S. Dep~ent of Energy, Energy Information Administration, An Analysis of Nuclear Power plant Operating COStS: A 1991 update,

DOE/EIA-0547, (Washington, DC: May 28, 1991). Capital additions costs (for major retrofits and repairs) have been highly variable.
26 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

owning utilities, is generally also a function of the

respective State regulators.48 In addition to regulating retail electric prices, many States also

regulate other aspects of utility operations in

some detail including IRP decisions related to

new capital investment and plant retirement. The

direct and indirect economic incentives established by State regulators and the Federal Energy

Regulatory Commission (FERC) can also play

important roles in plant life decisions. Members

of the public, including electricity consumers and

other interest groups, often intervene and otherwise participate in economic regulatory processes.

The objectives in nuclear plant life decisions

derive from the broader electric power system

objectives, including: assuring adequate supplies

to meet demand; minimizing the costs of electricity (including, increasingly, environmental costs);

equitably treating both electricity consumers and

plant owners in the recovery of costs; and,

increasingly, responding to intensifying market

forces in the electric power industry. Utilities and

State regulatory bodies are increasingly developing elaborate regulatory and planning processes

for evaluating electricity supplies to meet these

objectives.

As is typical in the electric utility industry,

there are major uncertainties in the factors determining economic plant lives. For example, in its

decision endorsing retirement of Unit One of the

San Onofre plant, the California Public Utilities

Commission was unable to determine whether or

not the plant would be cost-effective in the

future.49 Rather, it found that ‘there is substantial

evidence on both sides of the cost-effectiveness

issue’ and that the available analysis may not

provide a good indication of future performance.

50 Rather than representing a clearly optimal

choice, that and other retirement decisions involved professional judgment and a balancing of

the alternative choices and their uncertain outcomes. Because many factors in economic analyses are inherently subjective, some have suggested that certain past State regulatory activities

leading to plant retirement reflected an antinuclear bias rather than solid economic analysis.51

However, while there is certainly potential for

bias in any planning process involving the complex and uncertain factors found in the utility

industry, past retirement decisions do not provide

compelling evidence of regulatory manipulation.

The prospect of early power plant retirement

introduces some novel issues.52 In particular,

there is limited precedent in the economic regulation of the electric industry to guide the financial

treatment of capital invested, but not yet recovered in rates, following early plant retirement.

Similarly, there is little precedent for the treatment of shortfalls in decommissioning funds

resulting from early retirement. Of the six recent

early retirement decisions, unrecovered capital

and decommissioning costs ranged from a few

hundred million dollars for most to over $4 billion

for one.53 Consumers bore most or all of the costs

in three cases; in one case the utility bore the

unrecovered capital costs, and consumers bore

decommissioning costs; in the case of a public

413 Most nuclea pbts ~e o~rated by investor-owned utilities and fall under economic regulation by the Federal Energy Regulatow

Commission or State regulators. Five plants are publicly owned (e.g., by a public power authority). Three other operating plants are owned

by the Rmnessee Wiley Authority (TVA). TVA also has two previously operating units with Ml power licenses under review (Browns Ferry

1 and 3).

49 ~conmmt t. the Cobssion’s ~ce~~abut thep~t’s economics, he ~o~pubficUtifities Commission Division of Ratepayer

Advocates argued that the plant was demonstrably not cost effective.

so c~o~a pub~c Utilities commissio~ opinion on SONGS 1 Settletnent Agreement, Decision 92-0S4)36, Aug. 11, 1992.

51 See, e.g., Phillip Bayne, ‘‘Nuclear Power in 1992: A Year-End Review,’ remarks to The Energy DaiZy’s Annual Uh”/ity Conference, Dec.

10, 1992.

52 ~ese issues wo~d be relevmt to any early plant retirement, not just for nUClear titS.

53 me ex~eme exception is the sho~~ pl~t, which was retied before cornmerci~ operation >lX1.
Chapter 1--Overview and Policy Issues 27

power district, the owners and the consumers

were the same; and as of summer 1993, cost

recovery for one plant had not been decided.

Allowing a utility to recover its capital costs in

an early retirement is consistent with the traditional regulatory approach in many States where

the prudence of the plant investment is determined when the plant becomes operational (e.g.,

the plant is found to be “used and useful.”)

Further, not allowing a utility to recover its

investment in a plant retired early can create an

incentive to keep uneconomic plant in operation.

However, the concept of allowing capital recovery in early retirement is not without critics. For

example, some in the industry have suggested that

allowing favorable terms for capital recovery has

been used as an incentive for plant retirement by

State regulators biased against nuclear power.54

Finally, in those retirement cases in which plant

performance was poorer and costs were substantially higher than originally anticipated, there

may remain a question of whether the utility

performed adequately during the operating life of

the plant and whether some cost disallowances

are warranted.

B Federal Policy Considerations:

Supporting Economic Decisions

Although the Federal Government plays a

major role in guiding and supporting State

economic regulatory activities for electric utilities,55 Federal interests and influence over economic life decisions for nuclear plants are largely

indirect. However, Federal policies for safety

regulation, spent fuel disposal, environmental

protection, and research can have substantial

impacts on the long-term economy of existing

plants. The Federal policies listed in table 1-A

could help address several uncertainties related to

the economy of plant lives, helping States and

nuclear utilities make more timely and better

informed decisions.

1. Address Aging-Related Regulatory Safety

Issues.

Resolving aging-related regulatory safety issues could greatly reduce uncertainty about the

long-term economic attractiveness of existing

plants. Each of the policies discussed earlier

regarding safety regulation can have substantial

impacts on economic attractiveness. For example,

accelerating regulatory re-examination of aging

issues such as EQ and fatigue as they arise would

help clarify long-term capital additions requirements. Clarifying license renewal requirements

and demonstrating a workable process will similarly enable utilities and their economic regulators to determine better prospective plant lives,

and assess the economics of capital additions.

2. Address Federal Obligations for Nuclear Waste.

DOE’s lack of progress in developing both a

monitored retrievable storage (MRS) facility and

the ultimate repository for spent nuclear fuel have

been notable challenges to the economy of

existing plants. Many opportunities for, and

challenges to, speeding the development of an

MRS and the repository have been discussed

elsewhere, and are not the topic of this report.56

Notably, a recent DOE proposal suggested developing specialized casks for storage, transport, and

ultimately, disposal; and accepting commercial

spent fuel for interim storage at Federal sites.57

More recently, the Secretary of Energy has

suggested that the DOE should assume financial

M P. Bayne, “Nuclear Power in 1992: A Year-End Review, ” Remarks to The Energy Daily’s Annual Utility Conference, Dec. 10, 1992.

55 See, forexmple, tie Federal Power Act (1935), 16 U.S.C. 791~ the Public UtiliV Regulatory Policies Act of 1978 (P.L. 95-617 puRpA);

and the Energy Policy Act of 1992 (P.L. 102-486; EPACT).

56 See, e.g., U.S. con~ess, Office of lkchnology Assessment Managing the Nation’s Commercial High Level Radioactive Waste,

OTA-O-171 (Washington+ DC: U.S. Government Printing OffIce, lvkch 1985); and the National Research Council, 1991.

57 James D. wa~, Secretary, U.S. Department of Energy, letter to J. Bennett Jotitoum- Senate Committee on Energy and

Natural Resources, Dec. 17, 1992. See attachmen~ p. 2.
28 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

The Davis-Besse Nuclear Power Station, operated by

Toledo Edison Company, is one of seven operating

U.S. nuclear power plants designed by Babcock and

Wilcox (B&W). The members of the B&W Owners’

Group are working jointly to prepare a license

renewal application for one of the B&W plants, to be

selected later.

responsibility for spent fuel in 1998 if a final

repository is not yet available.58 Given the

importance of spent fuel disposal to continued

plant operation, the Federal Government could

consider additional options to clarify and fulfill

the Federal obligations for disposing spent nuclear fuel, helping utilities and States develop

appropriate plans for addressing their spent fuel

storage needs and costs.

First, the Federal Government could specify its

obligations if the 1998 Nuclear Waste Policy Act

(NWPA) deadline to open a high-level waste

disposal site is missed. The DOE could be

required to take title to the fuel and/or reimburse

utilities for the cost of constructing additional

storage facilities. Alternatively, the DOE could

modify its contractual agreements with utilities

by specifying the exact date the agency would

assume title to spent commercial fuel. The cost to

the Federal Government to reimburse utilities for

interim spent fuel storage could be on the order of

$20 million to $35 million in today’s dollars per

dry storage facility, plus operating costs. More

than enough, however, has been collected already

from utilities to cover the construction of sufficient dry storage at all their sites. At present, the

DOE lacks the express authority to reimburse

utilities, but this option could bean equitable way

to compensate licensees forced to manage waste

that they have been paying the Federal Government to dispose of beginning in 1998.

Second, it may be worth considering decoupling MRS construction from the licensing of a

geologic repository. Under NWPA as amended,

the construction of an MRS is prohibited until a

geologic repository is licensed, and only two are

allowed. 59 However, delays in repository characterization threaten the viability of the interim

MRS disposal option, because they impose an

automatic delay on MRS construction. In considering decoupling, it should be noted that the

growing number of dry storage facilities owned

and operated by utilities already represents the

creation of multiple MRS facilities, though each

on a smaller scale.

3. Expand Analyses of Nuclear Plant Economics.

The Federal Government has long been a

principal source of information on plant costs and

performance, and how those relate to the broader

electric industry context. Utilities and States are

increasingly devoting considerable resources to

such economic analyses, and in most cases they

are ultimately responsible for economic decisions. However, the large amount of resources at

stake in plant life decisions suggests that Federal

policymakers have a need for independent assessments of relative costs and performance. There

are several areas for improved information collec58 I~O~~qSPA~fDOE“obligation’” to Assme F~c~It~ponsibility in ‘98,” Electric Power Alert, VO1. 3, No. 12, June 9, 1993,

pp. 13-14.

59 Nucle~ Wrote Policy&t (NWPA) P.L. 100-203, 101 St@. 1330-236, VX. 5021.
Chapter 1-Overview and Policy Issues 29

tion and analyses. Progress in these areas would

provide better information for plant life decisions:

Improve nuclear plant cost data collected by the

Federal Government. As reported by utilities,

plant-specific operational costs have been estimated to understate actual costs for nuclear

plants by about 30 percent due to definitional

problems.60 Costs such as insurance and NRC

fees, for example, are not reported as plant

costs, but as utility-wide overhead.

Identify root causes of historical operational

and capital cost increases as a basis for future

projections. For example, one Energy Information Administration analysis of nuclear plant

operational costs identified research efforts

such as detailed regulatory case studies that

could help differentiate the effects of changing

NRC regulatory requirements from the effects

of new technology and information. Similarly,

research could be performed to help distinguish

between, and project the effects of, plant aging

(which should increase costs), and utility experience (which could either increase or decrease

costs).

Identify the causes for the wide variation in

costs and performance among the 107 existing

nuclear plants. For example, although some of

the wide variation in plant staff levels (a large

component of operational costs) is due to

different plant size and age, much of the reason

is unexplained.

Improve estimates of decommissioning costs

and cost escalation rates (see below).

Continue research into broader electricity market conditions and the application of IRP,

particularly considering the implications for

existing nuclear plants. Existing avenues for

this work are DOE’s IRP Program, which was

originally established in response to congressional initiatives; and in the development of the

DIP that the Energy Policy Act of 1992 requires

TVA to perform.61

4. Cofund Industry R&D for Existing Plant Issues.

Although the industry is developing many new

technologies to improve nuclear plant cost and

performance, many promising candidates remain

only partially pursued. This is true despite the fact

that the electric utility power industry is both

large (with revenues of about $200 billion annually) and mature. In its 1992 Research&Development Plan, the Electric Power Research Institute

(EPRI), identified attractive opportunities in nuclear operational cost control and safety improvements totaling nearly $60 million annually over

the plan’s 4-year planning horizon. EPRI estimates that only approximately half of that total

will be funded.62 A larger fraction of DOE’s R&D

effort could be devoted to existing nuclear plant

opportunities. For example, a recent National

Research Council study recommended a near

doubling of such research to $10 million, even

while substantially cutting DOE’s overall commercial nuclear R&D budget.63 The national labs

may be well-suited to performing some of this

work.

AFTER RETIREMENT: DECOMMISSIONING

After a nuclear power plant is retired, NRC

regulations require that decommissioning be performed to protect the public and the environment

60 H.1, BOWHS, L.c. FUllIX, M.L. Mycrs, cost Estinum”ng Rebionsh”ps for Nuclear Power plant operation ati Muinre~nCe,

ORIWI’M-10563, November 1987.

61 P.L. 102-486, Sec. 113.

62 Electric pOWa R~e~ch Institute, EPRIResearch & Development Plan 1992 (Pdo Alto, CA: J~u~ 1992).

63 Nation~ Re.mh co~cfl, Nuclear power: rechm”ca~ a& r~”~tional optio~ for r~e FU~re (wmo~ ~: National ACdt?lTly

Press, 1992), pp. 13, 175.
30 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

from accidental releases of the remaining radioactivity. 64 Decommissioning involves plant decontamination, reactor dismantlement, waste packaging, and finally, transportation of the waste to a

disposal facility. Decommissioning does not necessarily involve removal of all radionuclides from

a site. Rather it involves removal of sufficient

materials such that the resulting level of potential

exposure provides adequate protection of public

health and safety as determined by regulatory

agencies (see below).

Decommissioning experience worldwide is

limited thus far to small reactors (less than 250

MW) that generally had short lives and low

residual radioactivity. At present, the largest U.S.

reactor decommissioned to date has been the

small (72 MW) reactor at Shippingport. Larger

commercial reactors that are being retired today

or in the future, on the other hand, typically will

have operated longer and have far higher levels of

residual radioactivity.

Although no large commercial reactors have

undergone complete decommissioning yet, decommissioning experience with small reactors,

and with maintenance activities for operating

plants involving decontamination or removal of

large SSCs, suggests that the task of decommissioning large commercial nuclear power plants

can be accomplished with existing technologies.

Advances in technologies, such as chemical

decontamination methods and robotics, are being

used to perform decommissioning and to reduce

further occupational radiation exposures, Many

of the conventional technologies used to decommission nuclear power plants are the same ones

used to demolish other industrial facilities and

buildings, including torches, saws, and controlled

explosives. On the other hand, current technologies may require improvements if future residual

radioactivity standards, under development at the

NRC, are significantly more stringent than current criteria.

Waste disposal (including both spent fuel and

LLW) presents a major uncertainty in the prospects for performing commercial nuclear power

plant decommissioning. A primary activity of

decommissioning is to move radionuclides associated with low-level waste (LLW) from a plant

site to a LLW facility. Under the Low-Level

Radioactive Waste Policy Amendments Act of

1980, as amended (LLRWPA),65 responsibility

for developing LLW facilities rests with the

States, which are encouraged to form interstate

compacts. In the early 1970s, six LLW disposal

sites were available to commercial nuclear power

licensees. Three closed in the 1970s66 and another

(Beatty, Nevada) closed in January 1993. The two

sites remaining in operation are in South Carolina

(Barnwell) and Washington (Richland), both of

which are, or soon will be, restricted to members

of their respective compacts. No new LLW

disposal sites have been licensed, and legal and

other challenges have delayed or terminated

construction plans for all currently planned sites .67

In the interim, NRC rules allow, but do not

encourage, use of existing plant sites for LLW

a Complete plant dI“smantlement and site restoration may intuitively seem like basic elements in “decommis sioning” any nuclear or

non-nuclear facility, but these tasks are not necessary to address the radiological hazard at a nuclear power plant site. As a result, NRC

decommissioning rules do not require the dismantlement of nonradiological portions of nuclear power plants nor site restoration althoughphmt

owners may perform this other work.

65 p.Lo 99-240

66 ~ese ~= sites w~e in West wey, NY (closed 1975); Maxey Flats, KY (cIosed 1977); ad Sheftleld, ~ (CIOSd 1978). U.S.

Department of Energy, OffIce of Civilian Radioactive Waste Management, Integrated Data Base for 1991: U.S. Spent Fuel and Radioactive

Waste Inventories, Projections, and Characteristics, DOB/RW-0006, Rev, 7 (Washington DC: October 1991), p. 118.

67 R.R Zuercher, ‘‘Nebrm~ Ofilcials Going Back to Beginning to Slow I-I-W Site progress, “ Nucleonics Week, vol. 33, No. 21, May21,

1992, pp. 8-9; J. Clarke, “Deadlines Loom But No LLW Sites Open Ye4° The Energy Daily, vol. 20, No. 204, Oct. 22, 1992, pp. 1-2; U.S.

Congress, General Accounting tXf@ New York’s Adherence to Site Selection Procedures is Unclear, GAO/RCED-92-172 (Gaithersburg,

MD: August 1992); RR. Zuercher, ‘‘Illinois Back to Square One on LLW Disposal Facility Siting,” NucZeonics Week, vol. 33, No. 44, Oct.

29, 1992, pp. 4-5.
Chapter 1-Overview and Policy Issues ! 31

storage. Mixed wastes (i.e., chemical hazards that

are also LLW) raise special regulatory challenges

yet to be fully addressed.

Decommissioning costs will depend on many

factors including the approach used (e.g., the

length of storage before work begins); the nature

and extent of plant radioactivity and other site

contamination; local labor rates; waste disposal

costs; the number of reactors on a site; and

applicable State and Federal occupational and

environmental radioactivity standards.

Estimates of decommissioning costs have increased rapidly in the past several years for many

plants. Two factors introduce substantial uncertainty in current decommissioning cost estimates:

LLW disposal fees and the amount of labor

required to perform specific tasks. LLW disposal

and labor costs comprise the two largest portions

of estimated decommissioning costs (see figure

1-4). LLW disposal costs, currently estimated to

comprise about one-third of total decommissioning costs, have been rising several times faster

than inflation. The long-term prospects for siting

new LLW disposal facilities and their costs

remain uncertain.

Also, work difficulty, productivity, and scheduling conditions are difficult to determine reliably

in advance of actual decommissioning, suggesting there is no simple and accurate way to

determine the reliability of projected labor costs.

More experience decommissioning large reactors

in the future should reduce uncertainties in labor

cost estimation considerably.

S Standards for Timing and Thoroughness

of Decommissioning

As defined by NRC rules, decommissioning

involves removing a reactor from service and

reducing residual radioactivity to a level that

allows a site to be released for unrestricted use,

thereby allowing license termination. 68 However,

Figure 1-4-Decommissioning Cost Elements 1,175

MW Pressurized Water Reactor

---- ----

Y

Other

80/0

LLW disposal

380/o

SOURCE: G.J. Konzek and R.1. Smith, Battelle Pacific Northwest

Laboratory, Twhnology, Safety and Costs of Decommissioning a

Reference Pressurized Water Reactor Power Station: Technical Support for Decommissioning Matters Related to Preparation of the I%al

Decommissioning Rule, NUREG/CR_130, Addendum 4 (Washington,

DC: U.S. Nuclear Regulatory Commission, July 1988, p. 31.

NRC rules do not prescribe the conditions making

a site suitable for unrestricted use. Rather, the

determination of ‘how clean is clean enough?’ is

currently made on a site-specific basis using

interim NRC guidance criteria frost developed

almost two decades ago. 69 These criteria allow a

slightly elevated level of radiation relative to

pre-existing background conditions. In 1992, the

NRC initiated a process to revise the existing

criteria and develop more formal standards for

final site radiological release. The NRC expects

to promulgate a final rule in 1995.

The negative public and political reaction to

the 1990 “below regulatory concern” (BRC)

policy may indicate potential problems with the

6810 cm 50$2

69 us. Nuclear Regulatory Comrnissio~ Regulatory Guide 1.86 “Termina tion of Operating Licenses for Nuclear Reactors, ” June 1974.

Additional guidance was issued in the early 1980s.
32 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

current NRC residual radioactivity criteria. Depending on the site, States and the public may

have different expectations than the NRC about

acceptable levels of residual radioactivity. In

many cases, the levels of residual radioactivity

implied by current NRC guidance maybe acceptable but, in others, State and public concerns

about future land uses at decommissioned sites

may overshadow regulatory decisions over the

selection of any quantitative standards.

Recognizing that public acceptance will be

crucial to the success of the final site release

standards, the NRC has taken a novel approach to

the rulemaking. Called an “enhanced participatory rulemaking,” the NRC has conducted several public workshops prior to its development of

a proposed rule.70 In its rulemaking, the NRC is

considering a range of issues, including the

appropriate level and distribution of risk over

time between both the decommissioned site and

the LLW site; the use of costs and benefits in

selecting a risk level; and consistency with other

Federal laws protecting health and safety. Public

comments provided to the NRC have also raised

the question of whether allowing restricted land

uses at some sites may be a reasonable alternative

to the current goal of unrestricted release.

The effect such standards will have on total

decommissioning waste volumes, and thus costs,

is difficult to determine. However, unless new site

release standards are far more stringent than the

current requirements (e.g., requiring a return to

background levels), the effect on the technical

ability to perform decommissioning should be

minimal. More stringent standards could alter the

amount of material treated as low-level waste.

Because LLW disposal is a major portion of

decommissioning costs, more stringent standards

could result in greatly increased costs.

NRC rules specify the time period over which

decommissioning can be performed. The three

general types of decommissioning approaches

are: immediate plant dismantlement (known as

DECON), initial decontamination followed by a

storage period and subsequent dismantlement

(SAFSTOR), and enclosing and securing a facility for up to 60 years, followed by eventual release

of the site (ENTOMB) .71 The major advantage in

waiting to decommission a reactor is to allow

short-lived radionuclides, which account for most

of the residual radioactivity at nuclear power

plants, to decay naturally at the site. As the

radioactivity diminishes, potential occupational

and environmental radiation exposures are reduced. While the total volume of radioactive

waste requiring disposal may be relatively unchanged depending on the storage period, the

level of radioactivity would be lower.

Of the decommissioning approaches recognized by the NRC, the ENTOMB option, which

involves sealing and securing a site after a

minimal amount of decontamination and dismantlement, requires the least remediation over

the long term. ENTOMB involves costs for site

security and monitoring over an extended period.

However, monitoring and security costs may not

be great if another plant is operated on the same

site, which may be likely in many cases since the

transmission facilities and other infrastructure at

a site make it well-suited for another generating

plant.

The NRC considers 60 years a reasonable

period to complete decommissioning. However,

engineering studies indicate that the ENTOMB

option cannot assure sufficient radioactive decay

of long-lived radionuclides in the activated reactor vessel and its internal components to allow

To 57 Federal Register 58727-58730 (Dec. 11, 1992); ~d U.S. Nuclear Regulatory CO-sioq ‘‘Briefing on Rulemaking Process for

Developing Residual Radioactivity Standards for Decommissioning, ” Briefing to the Commission (ROckville, MD: Mar. 11, 1992),

71 10 CFR 50.82@)(l). Under SFid circumstances, the NRC will extend this period to about 100 years. See 53 Federal Register M23

(June 27, 1988).
Chapter 1-Overview and Policy Issues 133

site release within that time.72 Uncertainties about

the regulatory viability of the ENTOMB approach have made the option unattractive, even

though it could be useful in limiting radiation

exposures, waste volumes, and total decommissioning costs.

B Paying for Decommissioning

To assure that adequate financing is available

for decommissioning, the NRC requires utilities

to set aside funds over the life of a plant. The

funds required in NRC’s financial assurance

provisions are not intended to be cost estimates.

Rather, the NRC has stressed that its decommissioning provisions provide a reasonable approximation of the minimum costs. Further, the NRC’s

provisions exclude spent fuel management, even

though some storage costs are likely to be

incurred until the DOE takes receipt.

Although total decommissioning costs are

highly uncertain and are large if viewed as a

one-time expense, they are not large relative to

total production costs over the entire expected life

of a plant. Even at the high end of current

estimates, funds set aside for decommissioning

are only a few percent of production costs when

collected over a few decades of plant operation.

However, early retirement or rapidly increasing

decommissioning cost estimates toward the end

of a plant’s life may result in substantial underfunding of decommissioning accounts.

To address funding inadequacy for cases of

early retirement, the NRC promulgated a 1992

rule requiring case-by-case determinations of

licensee financial conditions.73 The preamble to

the rule stated that the NRC would allow the

collection of funds through the original license

expiration date, assuming that utility retained an

“A” bond rating. For a utility with an early

retirement unable to retain an A rating, total

funding within 1 year would be required. However, each of the six recent early retirements

required funding assurance mechanisms deviating from the NRC guidance in the new rule.

Several lacked the required bond ratings, while

others intend to accumulate funds beyond the

original license term.

1 Federal Policy Considerations for

Decommissioning

Absent license renewal, about three dozen

operating nuclear power plants will have to retire

in the next 20 years. More immediately, the

coming decade may bring several early retirements of large plants, which generally are larger

and more contaminated than the plants decommissioned to date. Commercial nuclear power

plant decommissioning, therefore, is likely to

become a much more visible issue in the next two

decades. However, final decommissioning of all

but a few very special cases will likely not be

performed before early in the next century.

Rather, most retired plants will go through at least

a several-year waiting period allowing short-lived

radioisotopes to decay.

There are several options beyond those currently being pursued that may help address

existing gaps in decommissioning policies. Of

greatest near-term importance are reconsidering

the goals for decommissioning and the adequacy

of decommissioning financing, and clarifying

policies for LLW disposal.

1. Revise Goals for Decommissioning Timing and

Site Release.

The NRC’s promulgation of final residual

radioactivity standards for site-release, scheduled

for completion in 1995, will play an important

role in filling a major gap in current decommissioning policy. Such standards will determine the

72 R.I. smith, G.J. Ko~e& and W.E. Kennedy, Jr., Battelle Pacific Northwest Laboratory, Technology, Sa~efy and costs ofDeco~”ssioning

a Reference Pressurized Water Reactor Power Station, NUREG/CR-0130 (Washington DC: U.S. Nuclear Regulatory Cornmissio~ June

1978), vol. 1, pp. V, 4-5 to 4-6.

7357 Federal Register 30383-30387 (JuIy 9, 1992).
34 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

ultimate scope and costs of decommissioning

work. As part of the rulemaking on site-release

standards, alternatives to the single current goal

of unrestricted use may be worth developing. In

some cases, cleanup to a level suitable for

unrestricted use may be neither necessary for

public health and safety nor economically desirable, because the expected radiation exposures at

a retired power plant site will vary depending on

its subsequent use. For example, agricultural

activities at released plant sites would introduce

different exposure pathways and doses compared

to residential use of the same area.74 Rather than

introduce the added occupational risk and economic cost of remediating a site to permit any

activity whatsoever (such as farming, for instance), it may be advisable in some cases to

remediate to a level allowing restricted use for

select activities, such as continued power production, provided that future exposures from those

activities will comply with regulatory goals and

standards for the protection of public and occupational health and the environment.

Nuclear power plant sites are developed industrial facilities, generally located near water, transport and electrical infrastructure, and some may

be well-suited for further power production or

other industrial activities, rather than farming or

recreational space, for example. Therefore, remediating a site to allow future uses unlikely to occur

may not be warranted from a health protection or

economic perspective. At the same time, States

and the public may accept or prefer restricted land

uses or access at some former nuclear facility

sites, based on concerns about health and safety

from any residual radioactivity on site. To increase the options to perform site cleanups that

protect public health and the environment and

that are economically feasible, alternatives to

unrestricted use may be worth considering, such

as restricted use for other industrial purposes.

The NRC could also clarify whether ENTOMB

is still a viable decommissioning strategy and, if

so, under what conditions. During a 1988 rulemaking, the NRC considered eliminating ENTOMB as a decommissioning option but instead

decided to develop more specific guidance on its

appropriate uses.75 No such guidance has been

forthcoming. In reexamining ENTOMB as an

option, the potential safety benefits (e.g., minimal

site work; lower occupational exposures; reduced

waste volumes; and deferred and reduced need for

permanent LLW sites) and the added challenges

(e.g., deferring responsibility to future generations; regulating retired plants as temporary LLW

sites) need consideration. Such a review could

consider variations of ENTOMB, such as removing the highly radioactive reactor vessel and

internal components prior to sealing and securing

the plant site. In some cases, ENTOMB maybe a

reasonable option to consider based on both

safety and economic reasons, and may be acceptable to the public.

Reconsideration of the ENTOMB option is a

natural extension of re-examining the concept of

unrestricted site release under certain circumstances. In particular, the extended period of site

restriction implied by the ENTOMB option suggests that the option may be appropriate in some

cases if restricted use becomes an acceptable

regulatory outcome of decommissioning.

2. Reconsider Adequacy of Decommissioning

Financing.

Early retirements and cost uncertainty both

raise questions about the adequacy of current

decommissioning fired requirements. Recent sitespecific estimates of decommissioning costs are

far higher than the NRC’s funding requirements.

T4 W7.E, Kenn~y, Jr., D.L. S&enge, Pacific Northwest Laboratory, ResidualRadioactive Contamination From Decommissioning: Technical

Basis for Translating Contamination Levels to Annual Total Effective Dose Equivalent, NUREG/CR-5512, vol. 1 (Washington, DC: U.S.

Nuclear Regulatory Commission October 1992).

7553 Federal Register 24023-24024 (June 27, 1988).
This is true for both plants retired early and those

expected to operate for their full licensed lives.

The NRC’s finding requirements use simple

sliding scales that establish the amount of financial assurance for each reactor according to its

size. However, size is not the only nor necessarily

most important determinant of decommissioning

cost. Moreover, utilities are increasingly using

site-specific estimates for State and utility economic planning, not the minimum NRC cost

figures. This raises the question of whether the

usefulness of the NRC figures could be improved

by reflecting better the expected-rather than

minimum--costs of decommissioning. Although

the NRC is performing an update of its original

studies, the topic may deserve considerably more

attention given the increasing number of plants

facing early retirement and decommissioning.

Further, the NRC’s recent rule addressing financing adequacy for early retirements bears reexamination, particularly in light of the fact that each of

the six plants recently retired did not meet the

conditions laid out in the rule’s preamble.

3. Clarify Regulatory Policies for Low-level Waste.

Disposal of LLW, including that mixed with

hazardous chemicals, rests with States. However,

the Federal Government retains responsibility for

setting standards for LLW (including mixed

waste) facilities. Until more LLW disposal facilities are available, waste may increasingly have to

be stored temporarily at plant sites. This practice

is allowed, but discouraged, by NRC rules. Given

that temporary storage may be unavoidable in the

Chapter 1-Overview and Policy Issues 135

near term, it may be worth reexamining safety

regulation of onsite storage of LLW, particularly

in the case of decommissioning. Two alternatives

for handling LLW in lieu of permanent disposal

sites are: deferring decontamination, reactor dismantlement, and waste packaging until a LLW

site is available; or performing that work, and

storing the packaged wastes at the plant until a

LLW site is available.

Mixed waste management remains an incompletely resolved regulatory issue. At present,

there are three commercial mixed waste disposal

sites (Colorado, Florida, and Utah), but their

disposal permits are restricted to select waste

groups with low activities.76 In the future, the

DOE may coordinate with States in the development of more mixed waste treatment and disposal

capacity, 77 but existing disposal capacity appears

insufficient to meet all commercial needs. The

NRC is responsible for regulating the radioactive

portion of mixed waste under the AEA. The U.S.

Environmental Protection Agency (EPA) has

direct responsibility or oversight of States in

regulating the hazardous chemical portion under

the Resource Conservation and Recovery Act of

1976, as amended.78 Congress could clarify the

regulatory responsibilities of the NRC and the

EPA. 79 Recent industry efforts to limit mixed

waste generation—source reduction, recycling,

processing, waste segregation-are notable, but

such efforts do not eliminate completely the need

for final disposal options.80

76 J A Klein et ~., O* ~dge Natio~~~ratory, Natio~[ Profile on Commercially Generated bw-bve[ Radioactive Mixed waSte, . .

NUREG/CR-5938 (Washington DC: U.S. Nucleat Regulatory Commission Deeember 1992), pp. 32-35.

71 U.S. Dep~ent of Ener~, Department of Energy Strategy for Development of a National Compliance Plan for DOE Mixed Waste,

predecisional draft (Washington DC: November 1992), pp. 4, 20,24.

78 p.L. 94-580, Oct. 21, 1976.

‘g For a detailed examination of these LLW policy issues, see U.S. Congress, OffIce of T@mology Assessment, Partnerships Under

Pressure: Managing Commercial bw-hvel Radioactive Waste, OTA-0426 (Washington, DC: U.S. Government Printing OffIce, November

1989).

go Rogers ad Associates Eq@eering COrp., The MaMgement of Mixed Low-Level Radioactive Waste in the Nuclear power I~ust~,

NUMARC/?N’ESP-006 (Washington, DC: Nuclear Management and Resources Council, Inc., January 1990), pp. 5-1 to 5-22.
36 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

4. Use Early Retirements as Decommissioning

Case Studies.

Finally, current and planned early retirements

provide an opportunity to learn more about the

adequacy of current decommissioning policies

and cost analyses. Even for those plants not

opting for immediate dismantlement, actual experience may help reduce much of the uncertainty

related to labor costs, the largest cost component

of decommissioning.

After a nuclear plant is retired and the fuel has

been removed from the reactor, the potential

public safety risks decrease greatly. For this

reason, NRC policy does not call for retaining the

NRC resident inspector during decommissioning

as required during plant operation. However,

given the lack of experience in large decommissioning projects to date, the NRC could consider

allowing utilities to request a resident inspector

on site during the first few large decommissioning

projects. The costs, borne by the utility, would be

small relative to direct decommissioning costs,

and may help improve communications between

licensees and the NRC, perhaps even leading to a

smoother and less expensive process.
I

Safety of

Aging

Nuclear

Plants 2

u

nchecked, aging degradation has the potential to reduce

the safety of operating nuclear power plants. The U.S.

Nuclear Regulatory Commission (NRC), the commercial nuclear power industry, and others engage in a range

of activities addressing the challenges imposed by power plant

aging. Many aging mechanisms are plant-specific and extensive

research efforts have been developed to address them, but no

technically insurmountable industry-wide safety obstacles have

been identified.

This chapter examines the safety issues related to nuclear

power plants as they age. The frost section describes the causes

and effects of aging degradation on nuclear power plant systems,

structures, and components. The second section reviews the

institutions involved and their roles in assuring the safety of

aging nuclear power plants. The third section describes industry

and regulatory processes used to address the safety impacts of

plant aging. The fourth section discusses the public and

occupational health and safety goals established in current policy

as they relate to aging nuclear power plants.

THE CAUSES AND EFFECTS OF NUCLEAR POWER

PLANT AGING

As defined by the NRC, aging is “the cumulative, timedependent degradation of a system, structure, or component

(SSC) in a nuclear power plant that, if unmitigated, could

compromise continuing safe operation of the plant. ’ The

nuclear power industry takes a broader view, noting that

unmitigated aging degradation can impair the ability of any SSC

to perform its design function,2 possibly affecting not only

safety, but also the economic performance and value of a plant.

c

‘ U.S. Nuclear Regulatory Commissio% Nuclear Plant Aging Research (NPAR)

Program P[an, NUREG-1 144, Rev. 2 (Washington DC: June 1991).

2 MPR Associates and the Electric Power Research Institute, Nuclear Power Plant

Common Aging Terminology, EPRI TR-1OO844 (Palo Alto, CA: Electric Power Research

Institute, November 1992), p. C-1.

I 37
38 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Many nuclear power plant SSCs are subject to

aging degradation, which can cause a variety of

changes in the physical properties of metals,

concrete, electrical cables, and other materials.

These materials may undergo changes in their

dimensions, ductility, fatigue capacity, or mechanical or dielectric strength. Aging degradation

results from a variety of physical or chemical

processes such as corrosion, fatigue, fabrication

defects, embrittlement, and mechanical effects

(box 2-A). These aging mechanisms can act on

power plant components from high heat and

pressure, radiation, and reactive chemicals. Some

plant operating procedures such as changing

power output and even equipment testing also

create stress for plant components.

Absent effective management, aging degradation increases the probability that any SSC will

fail to function properly. A failure may initiate a

system transient or accident sequence, and so

Box 2-A-Metal Aging Degradation Mechanisms

This is a partial listing of aging degradation mechanisms for metals, with examples of effects greater than

anticipated in plant design and methods used to address them.

Corrosion is the deterioration of a material resulting from reactions with its environment. Some steam generator

components, piping, pressure vessel internals, and other plant areas have experienced more extensive corrosion

than originally assumed during plant design. Major forms of corrosion include wastage, stress corrosion cracking,

erosion/corrosion, crevice corrosion, and intergranular attack. Methods of addressing corrosion for existing

components have been developed, including inspections for signs of deterioration, control of water chemistry, or

replacement with resistant materials or designs.

Fatigue is the deterioration of a material from the repeated cycles of thermal or mechanical loads or strains. The

number of cycles a material will tolerate until failure is used to classify it as either low cycle (withstanding less than

10 or 10 cycles) or high cycle. Together with the number of cycles expected, the magnitude of expected cyclic loads

is a key design condition. Some fatigue failures in piping and other components have occurred, often resulting from

larger than anticipated loads or combinations with other degradation mechanisms (e.g., corrosion). Methods of

addressing fatigue for an existing component include inspections and more accurate estimates and monitoring of

the magnitude and frequency of cyclic loads.

Fabrication defects can contribute to more rapid fatigue cracking and corrosion. Casting and forming defects and

weld-related defects embedded in a material may worsen from cyclic loadings, or such defects may become

exposed by corrosion. The distribution of flaws in a material is a key consideration, and design codes specify the

acceptable Ievel of fabrication defects. Methods of addressing fabrication defects for an existing component include

inspections using nondestructive examination techniques to detect embedded flaws early, and repairs when

necessary.

Embrittlement is a change in a material’s mechanical properties such as decreased ductility and reduced tolerance

to cracks resulting from thermal aging or irradiation. Some embrittlement has been found to be more rapid than

originally anticipated in plant design. Neutron irradiation of reactor pressure vessels (RPVs), for example, can lead

to a more rapid loss of ductility than expected, particularly when copper and nickel are contained in RPV weld

materials. Methods of addressing embrittlement for an existing component include more accurate estimates of

thermal exposure and neutron fluence histories and their effects, revised operations (e.g., arranging fuel to reduce

neutron flux to certain RPV regions), and component replacement or refurbishment (e.g., RPV annealing).

Mechanical effects include vibration, water hammer, and wear. Vibration and water hammer can result from fluid

flows and result in loads greater than explicitly considered during design, contributing to fatigue failures and damage

to pipes, valves, and pumps.

1 Stmcturd lnte9ritY Associates, Inc., Component b’fe Estimation: LWR Stmctural Materials D8g@%tion

Mechanisms, EPRI NP-5481 (Palo Alto, CA: Eleotric Power Research Institute, September 1987).
Chapter 2-Safety of Aging Nuclear Plants 139

Box 2-B–Reactor Pressure Vessel Embrittlement

After years of neutron bombardment from the reactor core, the steel that comprises a reactor pressure vessel

(RPV) can gradually lose some of its toughness in a process called embrittlement. Neutron embrittlement is

exacerbated if the steel or weld materials contain trace amounts of copper or nickel. The greatest potential problem

of RPV embrittlement is the threat of pressurized thermal shock (PTS). PTS leading to RPV cracking may occur

during certain abnormal plant events when relatively cool water is introduced into a reactor vessel while under high

pressure after a loss of coolant accident. U.S. Nuclear Regulatory Commission (NRC) requirements and the

American Society of Mechanical Engineers (ASME) Code for inspection and analysis are designed to ensure that

the pressure vessels are tough enough to resist cracking if PTS occurs.l

Although the role of copper and nickel in RPV embrittlement has been known for the past two decades, several

older plants were constructed using weld materials with traces of those metals. Because of the original conservative

1 IO CFR50.60 etseq.; US. Nuclear Regulatory Commlsskm, Re@atoryGuide 1.99, Revision2, “Radiation

Embrittlement of Reactor Vessel Materials,” May 1988; 10 CFR 50 Appendices A, G and H; and ASME Boiler and

Pressure Vessel Code Section Xl, “Rules for Inservioe Inspection of Nuclear Power Plant Components.”

(Continued on next page)

become noticeable immediately. However, not all

SSC failures are readily observable. For example,

the failure of an emergency diesel generator

(EDG), which is not used during normal operations but is needed only for backup power if

offsite power is lost, may not be noticed until it is

tested or called on to supply power. Also,

accidents may induce some SSC failures. For

example, aging may render electrical equipment

vulnerable to the conditions that arise from an

accident, such as changes in humidity, chemical

exposure, radiation, and temperature.3

The basic processes of nuclear power plant

aging are generally, if imperfectly, understood;

operating experience and research provide ongoing improvements in the scientific understanding

and ability to predict and address aging effects.

There is a fairly limited set of degradation

mechanisms, a large commonality in materials

used, and fairly similar plant operating conditions. However, due to the diversity in power

plant designs, construction and materials used,

operating conditions and histories, and maintenance practices, the specific effects of aging,

although similar, are unique to each plant. Even

near-twin units with the same management at the

same site can have substantial differences in the

remaining lives of their major SSCs.

For example, consider Baltimore Gas and

Electric’s two 825-megawatt (MWe) Calvert

Cliffs units. Construction licenses for both units

were issued in July 1969, and the same principal

contractor was responsible for both units. The

second unit was completed only 2 years after the

first and has a reactor pressure vessel (RPV) free

of copper and nickel, making it relatively immune

to neutron embrittlement (box 2-B). The Unit 1

RPV, however, was built before the discovery

that neutron embrittlement can occur more rapidly in steels with trace amounts of copper and

nickel. As a result, special procedures and mitigation measures are necessary for Unit 1 to attain its

full licensed life.4

3 Electrical equipment required to perform a safety function during or following a design basis event must be qualitled in accordance with

10 CFR 50.49, which includes aging considerations. As discussed below, the NRC and the commercial nuclear power industry are examining

the adequacy of these requirements.

4 Bwth DoroshuL Principal Engineer, Nuclear Engineering Departmen4 Baltimore Gas and Electric Co., personal communication June

9, 1992.
40 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Box 2-B–Reactor Pressure Vessel Embrittlement–-(Continued)

engineering designs and relative youth of most plants, only one plant to date, Yankee Rowe, has faced early

 retirement for embrittlement-related concerns. Fifteen other operating units currently do not meet generic screening

limits set by the NRC, and another two will similarly not satisfy the generic guidelines before the end of their licensed

lives.2 However, the NRC’s generic screening limits are intentionally conservative and do not necessarily indicate

an unacceptable level of embrittlement. Rather, failing to meet the genetic limit indicates the need for a more

detailed (e.g., plant-specific) analysis based on the ASME Code. During 1993, the NRC plans to validate licensees’

plant-specific data and analyses to determine that current requirements are met.3 While the NRC’s preliminary

assessment is that the industry RPV analyses are adequate, the differing professional opinions between NRC staff

and engineers in the case of Yankee Rowe indicate some potential for a challenging process of resolution.

The NRC and the commercial nuclear power industry both perform extensive research on RPV issues!

Improved analytical and nondestructive examination (NDE) methods (e.g., to characterize better the size and

distribution of RPV flaws, and the effects of cladding in crack propagation) may help determine if conservatism in

currently required margins can be reduced. In a recent report for the Electric Power Research Institute, the ASME

Section Xl Task Group recommended updating the current code based on improvements in such technical areas. 5

Several of the recommendations could result in Ionger estimated lives for RPVs, as more accurate methods replace

conservative assumptions in the present code. If more accurate analyses indicate that mitigation is needed, the rate

of embrittlement can be reduced by methods such as shielding the RPV wall, or placing the most depleted fuel

nearest the RPV’s most sensitive areas to reduce the rate of neutron flux. Other options for reducing PTS risks are

safety system design and operating procedures that reduce the frequency and severity of challenges (e.g.,

controlling heat up and cool down rates, reducing pressure prior to emergency coolant injection, and heating or

mixing emergency coolant).

To restore the toughness lost to embrittlement, a process called annealing has been routinely used at several

nuclear power plants in the former Soviet Union and for U.S. naval reactors.6 Annealing involves heating a vessel

to sufficiently high temperatures to allow the metal to regain its original properties. No such effort has been made

for commercial reactors in the United States, although EPRI and the NRC have supported research on the topic.7

After witnessing and investigating a successful Soviet annealment effort, a U.S. NRC-sponsored team concluded

that although there are some technical differences and issues to resolve, the basic process maybe applicable to

U.S. vessels.8

Embrittlement is not the only aging mechanism that can affect RPVs. Figure 2-1 shows an NRC summary of

the key degradation sites, aging causes, failure modes, and maintenance and mitigation actions for pressurized

water reactor (PWR) RPVs.9

2 U.S. Nuclear Regulatory Commission, “Statusof Reactor Vessel issues Inctuding Compliance with 10 CFR

Part 50, Appendices G and H,” SECY-93-048, Feb. 25, 1993. NRC also noted that one additional unit with an

indefinitely deferred construction schedule would not meet the limit at the end of its licensed life.

3 Ibi(’jm

4 U.S. NU&ar Regulatory Commission, Promedings of the Sen?hIaron ~SSeSW7?0f7~of ~mctwe Pmdktion

7iechno/ogy: Piping and Pressure Vesse/s, NUREG/CP-0037 (Washington, DC: February 1991); and “Pressure

Vessel Life-Cycle Management,” EPR/ Journa/Ootober/November 1991, pp. 32-33.

5 ASME Section Xl Task Group on Reactor Vessel Integrity Requirements, Wh/te f’aper on Reactor vessel

/ntegrity Requirements for Leve/A and B Conditions, EPRI TR-1OO251 (Palo Alto, CA: Eleotric Power Researoh

Institute, January 1993).

6 MPR Assodates, inc., Report on Annealing of the Plovovoronezh Unit 3 Reactor Vessel in thO USSR,

NUREG/CR-5760 (Washington, DC: U.S. Nuclear Regulatory Commission, July 1991).

7 Oak Ridge ~~w}at~ universit~s, me ~ngev~tyof~u~ear~o~~ Systems, EPRI NP-4208 (Palo ~to,

CA: Electric Power Research Institute, August 1985), Appendix A.

8 MpR Asso~ates, [nc,, Rep@ on Anne#ng of the Novovoro~zh Unit 3 Reactor Vess8/ in the USSR,

NUREG/CR-5760 (Washington, DC: U.S. Nuclear Regulatory Commission, July 1991).

9 U,so NU~ear Regulatory commission, NPAR Program p/an, N(JREG-1 144, Rev. 2 (Washington, DC: June

1991), p. 6.24,
Figure 2-l—Nuclear

Plant Aging Research

Program Summary of

Pressurized Water

Reactor RPV Aging

Issues

SOURCE: U.S. Nuclear

Regulatory Commission, Abdear

Plant Aging Research (NPAR)

Program Plan, NUREG-1 144,

Rev. 2 (Washington, DC:

June 1991, p. 6.24.

T- Con!rol rod dr(ve

mechan,. -

- Clo5ure flar)ge

Cladd$ng (~utlet nozzle

3jJEVe5sd wall

Reactor thickness

trans,t, on

core

Beltl,ne reqon

ac,d lea4+qe

SITES

Balti!ne ragon

OufieVlnlet nozzles

Instmmentabon nozzles

CRDM houslrg nozzles

Closure studs

Typcal PWR vessel showing lmpmtanf degradar!on Wes

Tem~r Xure (tarenhe,fl

4?

-300 0 300” ~

Temperature (cenflgrade))

Effacf of !rrad!at)on on the Charpy mpac[ energy for

a nuclear pressure vessel steel

SERVICE INSPECTION. SURVEILLANCE & MONITORING MITIGATION

0

I&

-.

C2
42 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

The useful lives of many power plant compo- life of a plant. In fact, many of these long-lived

nents, such as some pumps and valves, are shorter SSCs, including most RPVs and concrete structhan the expected life of the entire plant. These tures, appear adequate for periods longer than

components are replaced, refurbished, or repaired current license terms. However, some SSCs—

as part of regular maintenance efforts. In contrast, such as certain steam generators (box 2-C), RPVs

many other SSCs are designed to last the entire incorporating certain materials, and certain water

Box 2-C-Steam Generator Tube Corrosion and Cracking1

Steam generators (SGs) are integral to pressurized water reactors (PWRs), which comprise over two-thirds

of U.S. plants. Weighing between 250 to 675 tons, they are large heat exchangers located within a plant’s primary

containment and within the reactor coolant pressure boundary to transfer energy from the radioactive primary

reactor coolant to the nonradioactive secondary steam circuits that turn the turbines. Each PWR has two or more

SGs depending on plant design. Although originally designed to last the life of a plant, a variety of mechanisms

including corrosion, denting, cracking, and intergranular stress corrosion cracking, have been found to degrade the

thousands of tubes in many SGs much more rapidly than expected. Degradation can lead to leaks of radioactive

primary coolant and, in extreme oases, ruptured tubes leading to more severe plant problems. Each PWR has a

unique SG degradation history due to the diversity of design and materials and conditions such as water chemistry

and plant operating history.

Several methods are used to control SG degradation. Improved water chemistry is now widely used to reduce

the rate of degradation? inspections using nondestructive examination techniques are used to determine the

condition of the tubes. When inspections detect unacceptable levels of damage (e.g., cracks greater than 40 percent

of a tube’s wall thickness), various repair methods are used. Plugging removes a tube from service. An alternative

to plugging involves sleeving, or inserting anew tube inside the damaged portion of the original tube. Over 23,000

sleeves had been installed in domestic SGs as of 1990 (84 percent of which were at only four plants). Sleeved tubes

remain subject to degradation and may later need plugging. Heat treatment, chemical cleaning, and other methods

have also been used.

A plant can continue operating with a number of plugged tubes, as specified in plant operating manuals,

although plant efficiency is reduced with increasing numbers of sleeved or plugged tubes. When too many tubes

degrade too much, continued plant operation at its rated output requires steam generator replacement. Since 1981,

steam generators at more than 10 plants have been replaced, and several more are under consideration.

Replacement costs are high, often $100 to $200 million, and the work can take several months. For example, Duke

Power Co. anticipates spending $600 million on steam generator replacements for its McGuire-1 and -2 and

Catawba-1 plants between 1995 and 1997? A group of nine utilities has formed the Steam Generator Replacement

Group to make a volume purchase and thus reduce the replacement costs for its 16 PWRs.

The NRC and the commercial nuclear power industry continue working to improve the accuracy and

applications of nondestructlve examination techniques for steam generators. The NRC’s standard for plugging or

repairing a tube is the detection of a crack of a specific length extending through more than 40 percent of the tube.

However, the NRC has approved the use of different criteria for a few plants that have microcracks, and the agency

continues to investigate alternate criteria4 Figure 2-2 shows an NRC summary of the key degradation sites, aging

causes, failure modes, and maintenance and mitigation actions for PWR steam generator tubes.5

1 un[e~~ othe~~ n~ted, this information is ~nden~d from L. Frank ~e~ Gene~tor @ef’at@f

Expedence, Update for 1989-1990, NUREG/CR-5796 (Washington, DC: U.S. Nuclear Regulatory Commission,

December 1991); and S.E. Kuehn, “A new round of steam generator replacements begins,” PowerEnghedng, Juiy

1992, pp. 39-43.

2 pWR seoondary Water Chemistry @ideiines, Rev. 2, EPRi NP-6239, Deoember 1988.

36’Dljke Choo=s B&Wintern@iO@ to Supply 12 Steam Generators,” Nuc/eonics *k, vol. 33, No. 27, JuiY

2, 1992, p. 3.

4 U.S. Nuclear Regulatory Commission, W/tage-8ased h?ten”n? P/ugging Cdteria fOr Steam Genemtor

Tubes-Task Group Report, NUREG-1477 draft (Washington, DC: June 1993).

5 U.S. Nuciear Regulatory Commission, NPARProgram P/an, NUREG-1 144, Rev. 2 (Washington, DC: June

1991), p. 6.12.
Understsndlng snd

Materials

msnsging sglng @ PWR stssm generstor tubes ~ Steam wpamtom

Tub Incmnel &30 or 690

Tuba sheet W 5c9 clad wfh NlkCr-Fe alloy

(aqulvalent to SE 16s)

Tuba su~rts SA 2s5 Gr C FerrWc SS Type 4L25

or 409

Sleeves Incond 625 or nckel Lmndec! on

outsti surface II Inconel ~ or 690

Plugs Incenel 690

R=lrculatlng Westlnghouaa,

Oncf+through Combushon Englneermg,

E!abcock & Wll@3X

Steam generator types

S[ressors and

environment /

\

attack

‘Y Pnmav outlet

Primary o“tte!

Primary

outlet

Once- 7hrouyh steam generator

with md(cdted poblem areas

operating transients Recmculafmg steam generafo!

w!rh mdlcated p’oblem areas

I

AGING

CONCERNS

PWSCC (pure

water SCC) tubes

wmh low m,ll

a“nealmg

temperature are

more wscepttble

IGsCC IGA

TYPES SERVICE INSPECTION, SURVEILLANCE & MONITORING

Rec)rculatmg

,ns,de surfxe

SITES

U benc% roll !ranstmn

and dentaC rego.s

Tube @ugs

Ho! lag tubes m tub+lo

fubssheet crewce

ragon

Cold lag wde m sludge

pde or where scale

ccmtalmng cmppar

da~s(ts IS found

Tubes In tube support

ragtons

Rearculatmg

outsde

s“rface

Figure 2-2—Nuclear P,ttlng

Plant Aging Research

Program Summary of

Pressurized Water

Reactor Steam

Generator Tubes

Aging Issues

SOURCE: U.S. Nuclear

Regulatc@ornmission,r Vtdear

Plant Aging Research (NPAR)

Program P/an, NUREG-I 144,

Rev. 2 (Washington, DC:

June 1991), p. 6.30.

Denting

Inadequately suppatec!

tube (f dentad near the

top supfmrt plate

Hlgh~cle Iatlgue

Contact pants tmtween Frenlng

tube and an!wtxatmn

bar

Tubes sbove tubasheet Waatage

Eroslonarro%on

Faf79ue

Enwronmantal

faugue

OnC%-through

OutsIda

%rf~e

Tubas

Tubes m uw

tubeaheet rqon
44 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Life-cycle management activities at Baltimore Gas and

Electric Co.’s 2 Calvert Cliffs nuclear power plants

could be useful in future license renewal efforts.

system piping-may experience more rapid aging

degradation than originally anticipated in plant

designs. Because few nuclear power plants are in

the second half of their 40-year licensed lives,

operating experience with the aging of long-lived

SSCs remains limited.

INSTITUTIONS FOR ASSURING THE

SAFETY OF AGING PLANTS

Under the Atomic Energy Act of 1954 (AEA),5

as amended, the NRC is responsible for regulating civilian nuclear power facilities ‘to assure the

common defense and security and to protect the

health and safety of the public.”6 To ensure the

safety of operating nuclear plants, the NRC

performs a variety of activities, including the

development and documentation of the “licensing bases’ that specify plant design requirements

and operation and maintenance (O&M) practices;

the inspection and enforcement of license requirements; the performance of technical research and

analysis; and the modification of regulatory

requirements as needed. All of these activities are

involved in addressing power plant aging to

assure safe operations.

Although the NRC plays a central role in

assuring nuclear power plant safety, the AEA

actually assigns the primary responsibility for the

safe operation of a commercial nuclear plant with

the plant operator, or licensee.7 Each licensee is

ultimately responsible for the design, operation,

and maintenance of its plant-not only to meet

NRC requirements but to assure safety. To pool

resources, share experiences, and coordinate efforts, the U.S. nuclear electric utilities have

established several industry-wide organizations

concerned with safety and other issues. Notable

among them are the Electric Power Research

Institute (EPRI), the Institute of Nuclear Power

Operations (INPO), and the Nuclear Management

and Resources Council (NUMARC).

EPRI was formed in 1973 to perform research

and development (R&D) for a broad range of

electric utility industry technologies, including

nuclear power production. As discussed below,

EPRI has sponsored a great deal of R&D directly

related to nuclear plant aging issues over the last

two decades, ranging from basic material science

to improved maintenance practices. The organization helped prepare several of the 10 “industry

reports” on license renewal that were eventually

submitted to the NRC by NUMARC. Most, but

not all, nuclear utilities are EPRI members. As of

1992,7 utilities operating 23 of the Nation’s 107

5 Atomic Energy Act of 1954, Public Law 83-703, 68 Stat. 919.

b These responsibilities were originally granted to the Atomic Energy Commission (AEC). The Energy Reorg anization Act of 1974 (Public

Law 93438) transferred these responsibilities from the AEC to the U.S. Nuclear Regulatory Commission (NRC).

T 42 U.S,C. 2011 er seq.
Chapter 2--Safety of Aging Nuclear Plants 145

operating nuclear power plants were not members. 8

INTO was formed in 1979 in the aftermath of

the accident at Three Mile Island Nuclear Station

‘‘to promote the highest levels of safety and

reliability-to promote excellence-in the operation of nuclear electric plants. ’ All commercial

operators of nuclear power plants in the United

States are members. INPO performs evaluations

of plant practices, a form of self-regulation by

peer review. The organization also conducts

training and information exchange for its members. To promote effectiveness and encourage

better information exchanges between member

utilities, much of INPO's utility-specific work is

conducted as private transactions with its members, 10 although some of its reports are provided

to the NRC on a confidential basis.11 Some INPO

activities address aging-related issues, such as

promoting excellence in maintenance practices,

performing regular, onsite evaluations of plant

facilities and practices, and analyzing operating

events.

NUMARC, formed in 1987, acts as a liaison

between the nuclear power industry and the NRC

and other safety regulators on generic regulatory

and technical issues. All U.S. nuclear utilities are

members. Other nuclear industry organizations

such as nuclear steam supply system vendors and

architect-engineering firms also participate in

NUMARC efforts. The organization has played

an active role in addressing nuclear power plant

aging safety issues, including major contributions

in the development and implementation of NRC’s

maintenance and license renewal rules.

Professional societies such as the American

Society of Mechanical Engineers (ASME), the

Institute for Electrical and Electronics Engineers

(IEEE), the American Society of Civil Engineers,

and American Society of Testing and Materials

have developed codes and standards for the

design, maintenance, and analysis of various

SSCs. Code-writing committees affiliated with

these societies include individuals from utilities,

vendor firms, consultants, academia, and the

NRC. Several codes developed by these societies

for SSC design, qualification, and maintenance

have been incorporated in NRC rules.

The public and State governments also have a

role in promoting the safety of existing nuclear

power plants. As required by the AEA and the

Administrative Procedure Act, as amended,12 the

NRC solicits public comment when developing

new rules and regulations. The contribution is

often extensive. For example, NRC’s draft rule

for nuclear power plant license renewal drew

nearly 200 sets of comments, including 75 from

individuals, 42 from manufacturing and engineering firms, 40 from utilities and utility organizations, 19 from public interest groups, 8 from State

8 Nonmembers as of December 1992 (and the number of nuclear power plants operated by each) include Commonwealth Edison ( 12 units);

Virginia Power (4 units); Southern California Edison (2 units); Indiana and Michigan Electric (2 units); Detroit Edison (1 unit); Kansas Gas

and Electric ( 1 unit); and Washington Public Power Supply System ( 1 unit). Electric Power Research Instirufe 1992 Annual Report (Palo Alto,

CA: 1993), pp. 36-40; and U.S. Department of Energy, Nuclear Reactors Built, Being Bui/t, or Planned: 1991, DOE/OSTI-8200-R55

(Washington, DC: July 1992).

9 Institute of Nuc]W pOWf3r operations, “Institutional Plan for the Institute of Nuclear Power Operations, 1990, ” p. 5.

‘0 Ibid., app. B.

11 ~ls Pmctice has drawn some cl-iticism, For example, according to the U.S. General Accountig Office (GAO), on at least 12 masio~

during 1989 and 1990 the NRC decided not to issue publicly avaitable information notices after it was given access to INPC) documents that

were unavailable to the public. U.S. Congress, General Accounting Office, NRC’s Relationship With the Insn>tute ofNuclear Power Operations,

GAO/RCED-91-122 (Gaithersburg, MD: May 1991), p. 7. One public interest group filed a legal suit to gain access to INPO documents.

However, NRC’S practice of using coni3dential information has been affirmed by the U.S. Court of Appeals, finding no “reason to interfere

with the NRC’s exercise of its own discretion in dete rrnining how it can best secure the information it needs. United States Court of AppeaIs,

Critical Mass Energy Project, Appellant, v. Nuclear Regulatory Commission et al., 975 F.2d 871 (D.C. Cir. 1992), Aug. 21, 1992.

,J ~ USC, 551 et Seq”
46 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

agencies, and 4 from other Federal agencies.13

These comments led to several substantive revisions in the proposed rule.14 Similarly, comments

on the NRC’s proposed maintenance rule15 also

led to changes prior to its final promulgation in

July 1991.

The public may participate in NRC licensing

actions associated with operating nuclear power

plants that the NRC or the licensee initiates,

although some observers have suggested that

NRC policies have been too restrictive for public

input to help address many important safety

issues. 16 When a reactor licensee formally requests a modification or renewal of its NRC

license, the public may request a hearing and

intervene in the case, subject to certain administrative restrictions. For example, the public may

request a hearing in the case of a license renewal

application, but the scope of such hearings is

limited to circumstances unique to the renewal

term.17 The ultimate effect of public input during

NRC’s deliberations over license renewal applications remains to be seen and is likely to vary by

plant. Past experience with new plant licensing

indicates that the role of both local and national

public interest groups can be substantial.18

In contrast to the extensive opportunities for

public participation in the development of new

rules or during licensing actions initiated by the

NRC or licensees, NRC regulations place strict

limits on the public’s ability to initiate proceedings to modify, suspend, or revoke a license. NRC

regulations allow any person to file an enforcement petition with the Executive Director for

Operations (EDO), a member of the NRC staff,

specifying the action requested and the basis for

the request. The EDO’s decision in the case is

subject to review of the Commission, although

‘‘No petition for Commission review of a Director’s decision will be entertained by the Commission."19 These restrictions on petitioners’ Opportunities to seek Commission and judicial review

have been criticized as limiting the public role in

assuring plant safety. Although the requests in

most public petitions have been denied, they can

have notable impacts, as in the case of Yankee

Nuclear Power Station (box 2-D).

Because of the technical complexity of many

nuclear power issues, and because the perspectives of stakeholders can differ substantially,

resolving differing opinions when new issues are

raised can involve a lengthy process. For example, in developing and implementing license renewal policies, the NRC and the commercial nuclear power industry are reviewing the experience

of lead plants and other related industry efforts

before detailed renewal practices are finalized.

Some observers suggest that the regulatory

process itself is overly cumbersome and exacerbates uncertainty.

20 According to one NRC survey

Is U.S. Nuclw Re@atory Com.missiou Analysis of Public Comments on the Proposed Rule on Nuclear Power plant License Renewal,

WG-1428 (Washington DC: Oct. 5, 1991), Appendix A.

1-456 Federal Register 64943 et seq. @eC. 13, 1991).

1510 cm 5065,

16 ~~h=lle A&to, me Ution of Concerned Scientists, &&efy Second: The NRC and A~rica’s Nuclear Power P[ants @@uMpolis, ~:

Indiana University Press, 1987).

17 This limi~tion is consistent with NRC’s principles for the license renewal rob-that the current licensing basis provides adequate

protection of the public health and safety.

18 U.S. COWS5, mm of ~hnolow Assessment, Nuclear Power in an Age Of Uncertainty, C)’IA-E-216 (WaSh@tQ ~: U.S.

Government Printing Office, February 1984), ch. 8.

1910 cm 2.206.

2° M.W. Golay, “How Prometheus Came to be Bound: Nuclear Regulation in America,” Technology Review, Jnne/3uly 1980, pp. 29-39.

Although the article was written some time ago, the author contends that most of its themes remain pertinent. Personal communication January

1993.
Chapter 2-Safety of Aging Nuclear Plants 147

Box 2-D-Yankee Rowe

Until its early retirement in February 1992, the Yankee Rowe nuclear powerplant, a relatively small (185 MW)

PWR in Massachusetts, was the Nation’s oldest operating plant. The plant began operation in 1960 and was

expected to be the first to file an NRC license renewal application. During an NRC staff review of license renewal

documents, questions about the ability of the pressure vessel to withstand a pressurized thermal shock (PTS) were

raised.

In a petition filed with the NRC, the Union of Concerned Scientists asked for an immediate shutdown of the

plant.1 The petition emphasized several factors previously identified by NRC staff in its license renewal efforts.

Yankee Rowe’s case raised unique concerns related to the plant’s age. For example, the pressure vessel was

constructed before the susceptibility to neutron embrittlement of steel containing copper and nickel was fully

understood. As a result, those elements may have been included in the vessel’s weld material, although the extent

of their presence was unknown. Further, due to the unique cladding of the vessel, ultrasonic testing of the vessel

for cracks or flaws was not possible using conventional techniques.

Although shutdown request by the Union of Concerned Scientists was denied, the NRC initiated a review of

the plant’s PRA, which ultimately found that because of the uncertainties, the risk may have been greater than

previously estimated.2 The NRC revised its analysis to reflect the postulated detrimental effects of the vessel’s

metal cladding and made more conservative assumptions of potential cracks and the density of flaws in the vessel

and welds. The NRC staff recommended shutting the plant until testing of actual plant conditions could be

performed and the uncertainties resolved. This testing would involve applying specialized methods for obtaining

samples of the weld materials, and for positioning ultrasonic testing equipment in the 2-inch gap between the

vessel and cladding. Yankee Atomic Electric Co. concluded that the novel testing methods necessary to verify the

integrity of the reactor vessel, estimated to cost $23 million, were not economically justified and voluntarily removed

the plant from service and officially retired it 4 months later.3

1 Union of con~rned Scientists, letter to U.S. Nuclear Regulatory Commission, “Petition for E~rgency

Enforcement Action and Request for Pubiic Hearing Before the Nuclear Regulatory Commission,” June 4, 1991.

2 U.S. Nuclear Regulatory Commission, In the Matterof Yankee Atomic *tdC @m/XV?y: Me~ratiffmand

Order, CLI-91-11, July 31, 1991.

3 “NRC Staff, Yankee Atomic Continue Reactor Safety Debate,” 7he E?wgy Dai/y, Oct. 4, 1991, p. 4.

of industry members, respondents noted that achieve a higher degree of safety, if they were

‘‘licensees acquiesce to NRC requests even if the

requests require the expenditure of significant

licensee resources on matters of marginal safety

significance. Further, survey respondents noted

that the ‘‘NRC so dominates licensee resources

through its existing and changing formal and

informal requirements that licensees believe that

their plants, though not unsafe, would be easier to

operate, have better reliability, and may even

freer to manage their own resources.’’21

SAFETY PRACTICES ADDRESSING AGING

The practices necessary to manage nuclear

power plant aging are elaborate, beginning with

plant design and analysis and extending to a

variety of maintenance and research activities.

This section reviews the safety practices used to

manage plant aging.

‘1 U.S. Nuclear Regulatory Cornmissiou Industry Perceptions of [he Impact of the US. Nuclear Regulatory Comnu”ssion on Nuclear Power

P/ant Activities, draft report, NUREG-1395 (Washington DC: March 1990), pp. xxix.
48 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

B Nuclear Power Plant Design and Aging

Aging management begins with plant design.

Many design criteria explicitly or implicitly

address aging. The long-lived SSCs in a nuclear

plant, for example, were originally designed with

sufficient margins to meet minimum lifetime

requirements. Nuclear power plant piping systems are designed with industry codes based on

assumed service conditions, with some allowance

for pipe wall thinning from erosion and corrosion.

In addition, fatigue analyses used to establish

design criteria for piping, pumps, and valves

estimate the number of on/off cycles a power

plant experiences during its life, as well as the

resulting temperature variations and thermal stresses

from those cycles.

To account for a variety of engineering uncertainties at the time of plant design, original SSC

designs were generally based on what were then

thought to be conservative assumptions of operating and material conditions.22 Since the early

plants were designed and fabricated, decades of

experience and research have determined that

some design assumptions were in fact not conservative, while others were. As this experience

suggests, aging degradation rates for SSCs are in

some cases quite different than originally anticipated.

Over the past several decades, improvements in

analytical and material examination techniques

have allowed the review of original plant design

bases for more accurate assessments of aging

degradation. More accurate predictive methods

may allow for less conservatism in assessing the

adequacy of SSC performance and predicting

their remaining useful life. Some plants, particularly older ones, may lack the information needed

for more accurate analyses. At Yankee Rowe, for

example, the amount of copper in the RPV weld

material was unknown, preventing any ready

determinations of potential embrittlement problems. Many utilities have programs to improve

the availability and retrievability of design information, including efforts to reconstitute design

documents that were not adequately preserved.23

Technical understanding, industry practices,

and NRC design requirements have become more

rigorous since the 1960s. Prior to 1967, Atomic

Energy Commission (AEC)24 nuclear power plant

regulations contained relatively sparse design

detail. In 1971, the AEC adopted “General

Design Criteria (GDC) for Nuclear Power

Plants,” now contained in 10 CFR Part 50,

Appendix A. The GDC established minimum

requirements for materials, design, fabrication,

testing, inspection, and certification of all important plant safety features. The next year, a draft

“Standard Format and Content of Safety Analysis Reports for Nuclear Power Plants” provided

more detailed guidance and requirements for

implementing the GDC.25 Additional guidance

was contained in the Standard Review Plan,

originally released in 1975 and revised in 1981.26

Codes from professional societies that are

incorporated by reference in NRC regulations

have also changed substantially over the past

decades. For example, ASME codes for pressure

vessel design, fabrication, and operating limits27

evolved considerably from the 1960s through

1973, and in-service inspection requirements28

22 ASME Sectionm Ta&@oup on Rmtor vessel Integrity Requirements, White Paper on Reactor VesselIntegn”ty Requirementsfor tiel

A and B Conditions, EPRI TR-1OO251 (Prdo Alto, CA: Electric Power Rewarch Institute, January 1993), pp. 1-1 to 1-12.

23 Nucle~ -gement and Resources Council, Design Basis Program Guidelines, NUMARC 90-12 (Washington DC: October 1990);

and U.S. Nuclear Regulatory Commissio@ “Design Document Reconstitution” SECY-91-364, Nov. 12, 1991.

~ Re@atory authority and responsibiliti~ were transferred to the NRC by the Energy Reorg anization Act of 1974 (Public Law 93-438).

25 U.S. Nucle~ Re@~tol-y commission Regulatory Guide 1,70 is the f~ version of that draft document.

26 U.S. Nucle~ Re@atory Commission, Standard Review Plan, NUREG-0800 (Wuh@tOm DC: J~Y 198 1).

27 ~eficm socie~ of Mechanical Engineers, ASME Code, Section III.

28 &enca Sociew of Mechanical Engineers, ASME Code, Section ~.
Chapter 2-Safety of Aging Nuclear Plants 149

were introduced in 1970.29 Similarly, IEEE standards for electrical equipment issued in 1971 were

substantially revised in 1974.30

Some observers have suggested that the safety

of older plants is inadequate, because they were

not designed with the same detailed guidance as

newer plants and therefore often do not meet the

current design standards.31 However, the commercial nuclear power industry and the NRC note

that the NRC judges safety for older plants on an

ad hoc and plant-specific basis, rather than a

standardized basis, and the NRC finds that

adequate safety currently exists. To review and

ensure the safety of older plants, the NRC created

the “Systematic Evaluation Program” (SEP) in

1977. According to the NRC, the SEP review of

approximately 90 topics necessitated some specific procedural or hardware modifications (’‘backfits’ ‘), and additional analyses for the older plants

provided “reasonable assurance that they can be

operated without undue risk to the public health

and safety, which is the same standard for new

plants. 32

1 Maintenance Practices Addressing Aging

Effective maintenance programs are crucial to

manage aging degradation. Maintenance involves

a variety of methods to predict or detect aging

degradation and other causes of SSC failure, and

to repair or replace any affected SSCs. Both NRC

rules and industry codes contain maintenance

requirements. For example, the ASME Boiler and

Pressure Vessel Code Section XI specifies inservice inspection methods, which are incorporated in NRC rules.33 Before 1991, there were no

specific NRC maintenance requirements for many

SSCs important to safety. To ‘‘ensure the continuing effectiveness of maintenance for the lifetime

of nuclear power plants, particularly as plants

age, ” the NRC adopted a maintenance rule in

1991 to become effective in 1996.34 The rule

directs Licensees to establish performance goals

for SSCs important to safety and to monitor the

condition or performance of those SSCs, or

otherwise control degradation through preventive

maintenance. The requirements are relatively

flexible and do not specify performance criteria

(e.g., the frequency of testing or surveillance), and

the rule does not require a detailed regulatory

approval of the criteria licensees establish.

The maintenance rule was promulgated after

several years of increasing NRC and industry

attention to maintenance .35 While the NRC was

evaluating the need for a maintenance rule, INPO

developed guidelines for effective maintenance

to guide utility practices. 36 As a result, the

industry argued that the NRC rule was unnecessary and duplicated current practices established

by INPO. In promulgating its rule, the NRC noted

that its recent inspections of maintenance activities found that existing programs were adequate

and improving, but there were some areas of

weaknesses, and NRC found that no licensee had

formally committed to implement the INPO

2.9 ASME Section XI Task GOUp on Reactor vessel Integrity Re@rements, White Paper on Reactor VesselIntegn”ty Requirements for bel

A and B Conditions, EPRI TR-1OO251 (Palo Alto, CA: Electric Power Research Institute, January 1993), pp. 1-1 to 1-12.

30 ~sti~te of Electrical and Electronics Engineers S@&d, “Criteria for Protection Systems for Nuclear Power Generating Stations, ”

(IEEE-279), incorporated by reference in 10 CFR Part 50.55a(h).

s 1 See, e.g., D~e C-Comsel for Union of Concerned Scientists, Hean”ngs Before the Subcom”ttee on Energy and the Environment

of the Committee on Inten”or and Insular Ajlairs, House of Representatives, Nov. 5, 1991, pp. 93-95.

32 u s NuclWReW~toV co mrnission+ Foundationfor the Adequacy of thel,icensing Bases, NUREG-1412 (Washingto% DC: December

1991), p. 1.5.

3310 CFR 50.55a.

3410 cm 50.65.

M us. Con=ess, GenH~ &oufig Office, NRC’S Eflorts ?O E~ure Eflec~~e Plant Mainfe~nce Are Incomplete GAO/RCED-91-36

(Gaithersburg, MD: December 1990).

36 ~sti~te of Nuclear Power @erations, ‘‘Maintenance Programs in the Nuclear Power Industry,’ INPO 90-008, March 1990.
50 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

standards prior to the rule’s proposal.37 NUMARC

later submitted the INPO guidelines to the NRC

as an industry standard suitable for compliance

with the maintenance rule. The group also coordinated a validation and verification effort of the

maintenance approach at several nuclear plants,

and the NRC found them to describe adequately

the attributes necessary to comply with the

maintenance rule.38

There have been significant advances in nuclear plant maintenance technologies in the last

two decades in all areas, including surveillance,

testing, and inspection of important SSCs subject

to degradation; methods to plan repair, replacement, and other maintenance activities; and actual

SSC repair and replacement methods. All are

important to ensure that aging degradation does

not unduly reduce plant safety margins and

performance. There is a wide variety of specific

inspection, surveillance, testing, and monitoring

techniques used for the many different plant

SSCs. Examples of improved maintenance techniques for two major long-lived SSCs are given in

boxes 2-B (RPV embrittlement) and 2-C (steam

generator tube corrosion and cracking).

Effective maintenance requires the careful

planning and design of maintenance programs.

Two areas of improved planning approaches are:

1) predictive and reliability-centered maintenance (RCM)39; and 2) risk-focused maintenance

(RFM). RCM involves the use of prediction and

inspection techniques to repair or replace degraded critical equipment prior to its failure.40

Absent a reliability-based approach, much maintenance work focuses on either repairing failed

equipment as it occurs or repairing or replacing

equipment long before it wears out. In addition to

placing heavy reliance on the defense-indepth

approach designed into nuclear plants (e.g., redundancy of important safety items), reactive

maintenance in the extreme results in more plant

shutdowns and less coordination of maintenance

with fuel cycle outages. At the other extreme,

premature replacement of properly functioning

SSCs represents an unnecessary cost and increase

the potential for maintenance errors. RCM involves inspection and repair before SSCs wear

out but avoids excessive repair work through

monitoring and predictive techniques. The RCM

concept continues to evolve, for example, in

selecting an appropriate level of detail (e.g., to

examine systems or individual components) .41

RCM efforts, involving either pilot programs or

significant investments, are under way at about

half of the nuclear plants in the United States.42

NRC’s regulatory guide for the maintenance rule

encourages utilities to consider reliability-based

methods of predictive maintenance.43

RFM uses probabilistic risk assessment (PRA)

methods to determine which SSCs subject to

degradation are most important to safety and

performance and thus which should receive the 44 For example, greatest maintenance attention.

rather than perform an equal number of tests or

inspections on all of the many valves in a nuclear

power plant, those most important to reducing or

37 f(j FR 132, Jdy 10, 1991, p. 31321.

38 Nucle~ M~gernent and Resources Council, Indus~Guidelines for Moniton”ng Effectheness of Maintenance atNuclear Power Plants,

NUMARC 93-01 (Washington DC: May 1993); 56 Federal Register 31312 (July 10, 1991); and U.S. Nuclear Regulatory Comrnissio~

Regulatory Guide 1.160, June 1993.

39 ws Coqoratiou Predictive Maintenance Primer, EPRI NP-7205 (Palo Alto, CA: Electric Power R=~ch Institute, APril 1991).

a For ~uipment not critic~ to safety, the prescribed maintenance approach ~Y we~ be one of - until failure.

41 (,wWc Wmw N. Utilities Movfig fily on Mainte=e Rule Work’ Nucleonics Week, vol. 33, No. 42, Oct. 15, 1992, PP. 1* 13.

42 D.H. Worledge, ‘‘Nuclear Industry Embraces Reliability-Centered Maintenance,’ Power Engineerr”ng, July 1993, pp. 25-28.

43 U.S. Nuclear Regulatory Commission, Regulatory Guide 1.160, June 1993.

44 E.V, ~fwn et ~., A Process for Risk-Focused Mainte~nce, =G/cR.5695 ~utigton, DC: U.S. Nuclear Regulatory

Cornmissio@ March 1991).
mitigating accident risks are inspected more

frequently. RFM is also applied to EDG testing;

during any cold start for an engine such as a diesel

generator, the thermal stresses and mechanical

wear from the initial lack of lubrication contributes to substantial degradation and the potential

for premature failure. One RFM application has

allowed plant operators to reduce the frequency of

cold start EDG testing, while increasing the

testing of other emergency generator components

and support equipment, such as the starter systems. The result: longer and more reliable lives

for the EDGs and a higher expected availability

when they are actually needed.

Degradation detection methods for many SSCs

typically have imperfect accuracy,45 a factor to

consider when designing maintenance practices.

Improved testing and inspection techniques continue to be developed, allowing more accurate

and earlier detection of flaws and other material

characteristics, and improving the likelihood of

preventing the failure of important SSCs. New

nondestructive examination (NDE) methods—

including ultrasonic, eddy-current, and radiographic inspections of pressure vessels, steam

generators, piping, containment and other SSCs--

allow more accurate SSC evaluations than previously possible.46 For example, new NDE methods

based on magneto-optic imaging allow examination of containment welds for cracking, even

when these welds are beneath paint coatings.47

In addition, new methods are under development to examine some important SSCs that

currently preclude testing or inspection due to

Chapter 2--Safety of Aging Nuclear Plants 151

basic physical limitations (e.g., limited access or

space). New robotic technologies and other specialized inspection machines allow better access

to confined or high radiation areas.48 Robotics

applications include underwater visual inspections using submersible vehicles with cameras,

internal inspection of piping using power crawlers, and cleaning RPV internals and steam generators. After detecting cracks in RPV head penetrations at its Bugey-3 nuclear power plant, for

example, Electricity de France (EDF) decided to

inspect these penetrations at all 59 of its pressurized water reactors (PWRs). To reduce the

substantial occupational exposures resulting from

the detailed inspections, EDF worked with equipment vendors to develop a specialized robotic

inspection device to reduce exposures substantially. 49 The use of robotics in maintenance

activities is increasing, but improvements in

precision, dexterity, and mobility could increase

their usefulness further.

Unanticipated degradation

new repair and replacement

major SSCs. In some cases,

rates have inspired

methods for some

such as with some

PWR steam generators and boiling water reactor

(BWR) recirculation piping, these methods have

become widespread. However, replacing or repairing some SSCs may not be economically or

technically practical. Even where replacement or

repair is infeasible, life-limiting challenges may

be addressed through revised O&M practices;

such changes may reduce stresses on a vulnerable

SSC or may involve more regular monitoring to

detect incipient failure.

45 See, for exwple, P%ZIC Northwest Laboratory, Ultrasonic Inspection Reliability for Intergranular Stress Corrosion Cracks,

NUREG/CR-4908 (Washington DC: U.S. Nuclear Regulatory Commis sio% July 1990).

46 J.A. Jones Applied Re~tiCh Co., Nondestructive Evaluation Sourcebook, EPRI NP-7466-M (Palo Alto, CA: Electic Power Rese~h

Institute, September 1991).

47 physlc~ Rese~ch, ~o, Two New NDT Techniques for Inspection of Containment Welds Beneath coating, NUREG/CR-5551

(Washington DC: U.S. Nuclear Regulatory Cornmissiou June 1991).

48 v~i~~m~ac~rs Ro~t Usms Group, Suwq of utili~ Robotic Applications (~99(1), EpH Np-7456 (RIIo Alto, CA: Elw&ic power

Research Institute, August 1991).

4$1 { ‘Nucl~~dus~Deflwts Greenpeace on Cracking Issue, ” Nucleom”cs Week, vol. 34, No. 13, Apr. 1, 1993, pp. 1,9-12. The U.S. nuclear

power industry and the NRC expect to begin detailed inspections of PWR RPV head penetrations in 1994 when specialized machines become

available.
52 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Maintenance technologies continue to evolve,

and greater experience and implementation hold

the promise of safer, more reliable, and less costly

operations. To transfer the results of maintenance

R&D, EPRI has established a Nuclear Maintenance Applications Center in North Carolina.50

The Center provides a forum to impart EPRI

research findings and assists with training and

information exchange for nuclear utilities.

~ Aging Research

Both the commercial nuclear power industry

and the NRC view continued aging research and

analysis of operating experience as important to

help assure adequate safety. Both the industry and

the NRC perform research on a broad range of

aging topics, including basic materials science,

studies of specific components and degradation

mechanisms, new maintenance practices, and

analytical techniques.

Since its inception in 1973, EPRI has devoted

about 15 percent of its Nuclear Power Division

budget to understanding, detecting, and mitigating degradation processes for nuclear power plant

components. 51 The 1992 EPRI R&D plan included over $130 million in nuclear power

activities. 52 Similarly, the AEC and its successory, the NRC, have conducted research on

materials aging since 1960. About 25 percent of

the current $100 million annual NRC research

budget is dedicated to aging research.53 Most

NRC aging research is performed through Department of Energy (DOE) national laboratories.

Aging research is also conducted by some international organizations and other nations with

nuclear power plants.54

The goals of safety-related aging research are

varied and include the following:

understanding SSC aging effects that could

impair plant safety if unmitigated;

developing inspection, surveillance, monitoring,

and prediction methods to ensure timely detection of aging degradation;

evaluating the effectiveness of operating and

maintenance practices to mitigate aging effects; and

providing the technical bases for license renewal. 55

Absent actual, long-term operating experience for

long-lived SSCs, scientific understanding of aging

issues involves engineering analyses and research, often using simulation techniques to

accelerate aging on test materials.56 Retired plants

may also yield lessons about aging by providing

naturally aged SSCs to study. For example, the

NRC, the DOE and the commercial nuclear power

industry are coordinating efforts to examine

materials from the retired Yankee Rowe plant,

which operated for 30 years, to aid in aging

research. 57 However, the diversity among plants

and their SSCs prevents simple generalizations

about the ultimate effects and management of

aging. In contrast, for shorter lived SSCs, engi50 see, forex~ple, Elec~c Power Reseach~ti~te, EPMResearch Publications, Products, andExpertise in Maintenance, Epw Np-7014

(Palo Alto, CA: May 1991).

51 John Carey, Electric Power Research Institute, personal Cornmunicatio% JiUN.KUY 1993.

52 See, for ex~ple, Electric Power Research Institute, Research and Development Plan 1993, (Pdo Alto, CA: 1993).

53 U.S. NucleW ReWlatoV Comissio%BudgetE~ti~te$Fi$ca/ years 1994.~995, NUREG 1100, vO]. 9 (Washington, DC: April 1993),

pp. 48, 51.

54 see~temtiOn~Ato~CEnav Agen~y, Safe~A$pect$oflhe Aging andMainte~nce ofNuclearPowerplants, (Vienna, Austria: 1988);

and International Atomic Energy Agency, Su~ety Aspects of Nuclear Power Plant Ageing, IAEA-TECDOC-540 (Vienna, Austria: 1990).

55 U.S. Nuclear Regulatory Comrnissioq Nuclear Plant Aging Research (NPAR) program plan, NUREG-1 144 Rev. 2 (Washington, DC:

U.S. Nuclear Regulatory Comrnissiou June 1991), p. 1.4.

56 u~versi~ of co~~ticu~ Natura/ Versus A~ifi”cial Aging of Nuc/ear Power plant Components, ~~ TR-100245 (pdo AltO, CA:

Electric Power Research Institute, January 1992).

5758 Federa[ Register 8998-8999 (Feb. 18, 1993).
Chapter 2-Safety of Aging Nuclear Plants! 53

neering analyses and aging research are supported

better by actual operating experience.

According to the NRC, “there are significant

uncertainties about aging degradation processes

and about whether time-related degradation can

be detected and managed before safety is impaired. ’ ’58 However, no incurable safety problems have yet been identified by NRC aging

research studies. Rather, NRC research has improved the understanding of aging issues and the

adequacy of maintenance efforts. These research

findings are transferred to NRC regulatory activities, including plant inspections and revisions of

technical specifications.59 Figure 2-3, which shows

the results of research on BWR recirculation

piping, provides one example of how information

gained from aging research has influenced regulatory and operating practices. As of 1991, the NRC

anticipated the completion of its Nuclear Plant

Aging Research (NPAR) program as currently

formulated by 1997 (’box 2-E), although that

schedule is not firm (tables 2-1 and 2-2).60 Even

with the completion of the NPAR program,

research will be needed to examine new maintenance methods and to address any new issues

identified through operating experience and past

research.

The results of generic SSC aging evaluations

relevant to license renewal are documented in 10

industry reports produced with industry and DOE

funds. The reports were produced by EPRI and

DOE’s Sandia National Laboratory for

NUMARC, and NUMARC submitted them to the

NRC for an evaluation of their applicability for

utilities submitting renewal applications. These

reports are intended to examine all plausible

aging degradation mechanisms, and identify combinations of components and degradation mechanisms for which existing programs do not effectively manage the degradation. Consistent with

the results of NRC’s research, this effort identified no incurable safety challenges, and found

that most component degradation mechanisms

are effectively managed by current plant programs. However, plant-specific challenges may

exist, and several areas for further examin ation

were identified. As with much of NRC’s aging

research, these documents are generic rather than

plant-specific.

B External Review of Nuclear Power Plant

Activities

Regular external review of nuclear utility

power plant and corporate activities in the form of

safety inspections and evaluations is fundamental

to ensure safety for plants of all ages.61 Outside

inspections and evaluations of licensee performance are conducted by both the NRC and INPO.

Some external review activities are closely related to concerns about plant aging. For example,

reviews of utility maintenance practices can help

ensure that those activities are performed adequately and will effectively identify degradation

related to aging or other causes.

INPO evaluations of operating plants and

corporate organizations involve in-depth team

reviews conducted at an average interval of about

16 months.

62 The INPO evaluation reports are

provided to the utility and are available to the

NRC resident inspector but are not public documents. Subsequent INPO evaluations assess the

58 U.S. Nucle~ Reguktory Commission, Annual Report 1991, NUREG-1 145, vol. 8 (Washington+ DC: JulY 1N2), P. 161.

59 W. Gun~er and J. Taylor, Bmotiven National Laboratory, Results j%om the Nuclear Plant Aging Research program: Their Use in

Inspection Activities, NUREG/CR-5507 (Washingto4 DC: U.S. Nuclear Regulatory Commission September 1990); and U.S. Nuclear

Regulatory Commission, Nuclear Plant Aging Research Program Plan, NUREG-1 144, Rev. 2 (Washington, DC: June 1991), pp. 6.23-6.33,

60 ~wrence Stio, Director, &@Wfig Divisio~ ~lm of Nuclem Re@atory Rese~~ U.S. Nucle~ Regulatory Commissio% pe~ollid

communication, February 1993.

61 U.S. Nuclear Regulatory CO rnrnission, Annual Report 1991, NUREG-1 145, vol. 8 (Washington DC: July 1992), pp. 19-25.

62 ~sti~te of Nuclear Power opemtiom, “Institutional Plan for the Institute of Nuclear’ Power Operations,” Appendix A.
—.

Figure 2-3-Nuclear

Plant Aging Research

Program Summary of

Boiling Water Reactor

Recirculation Piping

Aging Issues

SOURCE: U.S. Nuclear

~~~m~,~~r

Plant Aging Reseati (NPAR)

_*, NUREG-1 144,

Rev. 2 June 1991, p. 6.32.

SITES

Sites w!th crewces and small

amount of cold work

AGING CONCERNS SERVICE tNSPECTION, SURVEILLANCE & MONfTORING

.

.

.

.

.

.

a’
Chapter 2-Safety of Aging Nuclear Plants 155

Box 2-E—The Nuclear Regulatory Commission’s Nuclear Plant Aging Research Program

Under the U.S. Nuclear Regulatory Commission’s (NRC’s) Nuclear Plant Aging Research (NPAR) Program,

aging assessments have been or are being performed on over 40 categories of systems, structures, and

components (SSCs) considered significant to safety, many of which are relatively short-lived.’ These SSCs were

selected based on their significance to plant safety, operating experience, expert opinion, and susceptibility to

aging degradation, not necessarily whether they are short- or long-lived.

A one- or two-phase examination is performed for each SSC. Phase I involves a paper examination, including

review of the design, materials, and operating stresses and a survey of operating experiences and historical

failures for the selected SSC. Also, the existing SSC inspection and monitoring methods are examined to

determine their effectiveness in detecting aging degradation before failure occurs. Often, the adequacy of artificial

or accelerated aging techniques used to qualify the SSC for its design lifetime are compared to available data from

their naturally aged counterparts. The result of a Phase I evaluation is an interim assessment of probable failure

modes.

Phase-II NPAR assessments, which the NRC may deem unnecessary depending on Phase I results, may

involve laboratory tests of naturally or artificially aged equipment; aging assessments by experts; recommendations for inspection or monitoring techniques; and in-situ examinations. As shown in the tables, analyses have been

performed for many SSCs, but several have yet to be initiated.

Because of substantial variations in hardware and procedures at U.S. operating nuclear plants, the NRC

examinations are not intended as in-depth engineering evaluations of all significant SSCs. That responsibility

ultimately belongs to the operators of each nuclear plant. This is particularly the case with major components and

structures such as pressure vessels, emergency diesel generators (EDGs), or primary containment, for which

laboratory examinations are infeasible.

For example, nuclear power plant EDGs are large and complex, with about 25 models supplied by nine

vendors in current use. Because naturally aged EDGs on which to perform indepth laboratory examinations are

not available, the NPAR program approach is to use expert opinion drawn from national laboratories, consultants,

manufacturers, and utilities to examine historical failures and to identify the components most vulnerable to aging

and identify mitigation measures.

1 Structural and materials aging research are conducted under separate programs at the NRC.

2 K.R. I+oopingarner and F.R. Zaloudek, Pacific Northwest Laboratory, Aghg hfitigabn and /mProved

Programs for /Vuc/ear Service Diese/ Genertors NUREG/CR-5057 (Washington, DC: U.S. Nuclear Regulatory

Commission, March 1989).
56 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Table 2-l-Systems and Components in the Nuclear Plant Aging Research Program

and Their Completion Schedule

Topic Laboratory Schedule

Components

Motor-operated valves

Check valves

Solenoid valves

Air-operated valves

Auxiliary feedwater pumps

Small electric motors

Large electric motors

Chargers/inverters

Batteries

Power-operated relief valves

Snubbers

Circuit breakers/relays

Electrical penetrations

Connectors, terminal blocks

Chillers

Cables

Diesel generators

Transformers

Heat exchangers

Compressors

Bistables/switches

Main steam isolation valves

Accumulators

Surge arrestors

Isolation condensers (BWR)

Purge and vent valves

Safety relief valves

Service water and component cooling water pumps

Systems

High-pressure emergency core cooling system

RHR/Low-pressure emergency core cooling system

Service water

Component cooling water

Reactor protection

Class 1 E electric distribution

Auxiliary feed water

Control rod drive, PWR (W)

Control rod drive, PWR (B&W, CE)

Control rod drive, BWR

Motor control centers

instrument air

Containment cooling

Engineered safety features

instrument and control

Automatic depressurization (BWR)

Standby liquid control (BWR)

Core internals

Turbine main generator and controls

Containment isolation

Recirculation pump trip actuation instrumentation (BWR)

Reactor core isolation cooling

ORNL

ORNL

ORNL

ORNL

ORNL

ORNL

BNL

BNL

INEL

ORNL

PNL

BNL, Wyle

SNL

SNL

PNL

SNL

PNL

INEL

ORNL

ORNL

BNL

ORNL

INEL

BNL

PNL

BNL

INEL

INEL

ORNL

BNL

BNL

ORNL

BNL

BNL

BNL

PNL

ORNL

PNL

PNL

ORNL

ORNL

Complete in fiscal year 1991

Complete in fiscal year 1991

Complete in fiscal year 1991

initiate Phase 1 in fiscal year 1991

Complete in fiscal year 1991

Completed in fiscal year 1988

Initiate phase 1 in fiscal year 1992

Completed in fiscal year 1990

Completed in fiscal year 1990

Completed In fiscal year 1989

Complete phase 2 in fiscal year 1991

Complete phase 2 in fiscal year 1991

Complete phase 1 in fiscal year 1991

Initiate phase 1 in fiscal year 1991

Initiate phase 1 in fiscal year 1991

Complete phase 2 in fiscal year 1991

Phase 2 completed in fiscal year 1989

Complete phase 1 in fiscal year 1991

Complete phase 1 in fiscal year 1991

Phase 1 completed in fiscal year 1990

Initiate phase 1 in fiscal year 1991

Initiate phase 1 in fiscal year 1991

No initiative

No initiative

No initiative

No initiative

No initiative

No initiative

Complete phase 1 in fiscal year 1991

Complete phase 2 in fiscal year 1991

Phase 2 completed in fiscal year 1990

Complete phase 2 in fiscal year 1992

Complete phase 2 in fiscal year 1991

Complete phase 2 in fiscal year 1991

initiate phase 1 in fiscal year 1991

Phase 1 completed in fiscal year 1990

Complete phase 1 in fiscal year 1991

Complete phase 1 in fiscal year 1991

Completed in fiscal year 1989

Complete phase 2 in fiscal year 1992

Complete phase 1 in fiscal year 1991

Initiate phase 1 in fiscal year 1991

Complete phase 1 in fiscal year 1992

Complete pre-phase 1 in fiscal year 1991

Complete phase 1 in fiscal year 1991

initiate phase 1 in fiscal year 1991

initiate phase 1 in 1991

No initiative

No initiative

No initiative

SOURCE: U.S. Nuclear Regulatory Commission, Nuclear Plant Aging Research (NPAR) Program P/an, NUREG-1 144, Rev. 2

(Washington, DC: June 1991).
effectiveness of utility actions to address previously identified items.

The NRC inspection program is intended to

evaluate plant compliance with the current licensing basis (CLB) (box 2-F), to determine reactor

safety, and to identify conditions that may warrant corrective actions. The inspection staff also

collects information used in the NRC Systematic

Assessment of Licensee Performance (SALP)

evaluations (box 2-G). Each operating plant has at

least one full-time, onsite NRC resident inspector.

The resident inspectors directly observe and

verify licensee activities in the control room, in

maintenance and surveillance testing, and in the

configuration of equipment important to safety,

and they conduct frequent general plant tours, In

addition to the regular duties of resident inspectors, inspectors from the five NRC regional

offices and the NRC headquarters periodically

perform a variety of more detailed technical

inspections.

NRC team inspections are conducted by technical specialists drawn from both the NRC and its

contractor organizations (e.g., the national laboratories). These specialists spend several weeks at

a plant investigating a specific topic, such as

maintenance, emergency operations, or the testing of motor-operated valves. Maintenance Team

Inspections in which all maintenance-related

plant activities were observed in detail were

conducted at all plants in the late 1980s and early

1990s. These inspections found adequate programs and implementation at all sites. These

favorable findings partially explain why the NRC

promulgated a relatively flexible maintenance

rule in 1991.63

Chapter 2--Safety of Aging Nuclear Plants 157

Table 2-2-Completed Nuclear Plant Aging

Research Life Assessments for Major Components

Emergency diesel generators

Pressurized Water Reactor (BWR) and Boiling Water Reactor

(BWR) pressure vessels

BWR Mark I containments

PWR and BWR pressure vessel Internals

PWR cooling system piping and nozzles

PWR steam generator tubes

Pressurizer, surge and spray lines

BWR recirculation piping

LWR coolant pumps

SOURCE: U.S. Nuclear Regulatory Commission, Nuclear P/ant Aging

Research (NPAR) Program P/an, NUREG-1 144, Rev. 2. (Washington,

DC: June 1991).

I License Expiration and Renewal for Aging

Management

The AEA specifies that commercial nuclear

plant operating licenses may not exceed 40 years

but may be renewed upon expiration.64 The fixed

term was established in the AEA for financial and

other nontechnical reasons, although once chosen, it became an assumption in specifying certain

plant design features (e.g., the number of thermal

cycles occurring, and thus the requirements for

addressing fatigue).

NRC license renewal requirements center on

the management of aging degradation. As a result

of its license renewal work, the NRC staff

identified fatigue and environmental qualification of electrical equipment (EQ) as possible

generic safety issues to be examined for all plants

during their current license terms. 65 The importance of fatigue and EQ to aging is well known to

both the commercial nuclear power industry and

the NRC, and considerable attention has been

directed to these issues (box 2-H). Rather than

identifying new aging issues, examining these

6356 Federal Register 31321 (July 10, 1991).

64 Llceme ~em ~we fi~y ~etb~d on the ~W of ~lmt com~ctionrathm~ the s~of operation. However, the NRC h&s established

a relatively simple administrative procedure to recover the construction period and thereby extend the expiration date of the initial opemting

licenses without renewal. Memorandum from W.J. Dircks, Executive Director for Operations to the Commissioners, U.S. Nuclear Regulatory

Cornrnissiou Aug. 16, 1982. To date, over ftity such extensions have been granted. 58 Federal Register 7899. Feb. 10, 1993.

65 U.S. Nuclw Regulatory CO remission, Implementation of 10 CFR Part 54, ‘Requirements for Renewal of Operating Licenses for Nuclear

Power Plants,” SECY-93-049, Mar. 1, 1993.
58 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Box 2-F-Current Licensing Bases

A plant’s current licensing basis (CLB) includes all NRC requirements, whether made during initial licensing

or as modified over time.1 This large body of requirements is contained in a variety of documents, including:

● a plant’s operating license application or Safety Analysis Report;

■ plant-specific compliance with NRC regulations noted in 10 CFR Part 50, as well as other parts of Title 10 of the Code

of Federal Regulations;

● NRC orders, license conditions, exemptions, and technical specifications; and

● all written commitments made by the licensee in docketed responses to NRC bulletins and generic letters.2

NRC regulations and industry practices draw on the codes and standards of many organizations such as the

American Society of Mechanical Engineers, the Institute for Electrical and electronics Engineers, the American

Society of Civil Engineers, and American Society of Testing and Materials.

The CLB for each plant is unique. Differences result from variations in plant siting (e.g., a plant located near

an active fault requires special seismic protection features); plant design (e.g., whether a boiling or pressurized

water reactor, the number of steam generators); different regulations and regulatory interpretations in effect at the

time of licensing; and plant operating experience (e.g., special problems leading to additional commitments to the

NRC). Many NRC requirements, such as the maintenance rule, explicitly address aging safety issues.

1 For additional discussion of the NRC’s views of current ikendng bases, see U.S. Nuclear Regulatory

Commission, Foumfatlon fix the Adequacy of the Licensing 6ases, NUREG-1412 (Washington, DC: Deoember

1991).

z In itg effort to provide the oornrneroial nuclear power Industry Information on operating experience, each

year the NRC issues about 5 generic bulletins, about 20 generic ietters, and about 100 information notioes. Scienoe

Applications international Corporation, @nedc Conwnun I&Wons Index, NUREG/CR-4690 (Washington, DC: U.S.

Nuclear Regulatory Convnission, May 1991). Although the informal guidance does not carry the same legal authority

as regulations, iioensees are often motivated tu dctress the issues raised Their docketed responses to the generic

communications then become part of the plant’s formal requirements.

topics as generic safety issues provides a method 2. each plant’s CLB must be maintained durfor identifying and prioritizing issues based on

potential safety significance and implementation

costs .66

The NRC license renewal rule is founded on

two key principles:

1. With the exception of age-related degradation unique to license renewal (ARDUTLR),

and possibly some few other issues related

to safety only during extended operation,

the existing regulatory process is adequate

to ensure that the licensing bases of all

currently operating plants provide and maintain an acceptable level of safety; and

ing the renewal period, in part through a

program of aging degradation management

for SSCs that are important to license

renewal. 67

If approved, the renewed License would supersede the existing license, with the requested

extension period increased to reflect the time

remaining under the current license.

In any event, the duration of the renewal license

would be limited to 40 years, including an

extension of no more than 20 years. The NRC has

estimated that the effort required by a utility to

submit a license renewal application would re66 U.S. Nuclem Re@~to~ Commission, A Pn”on”tization of Genen”c Safety Issues, NUREG-0933, semi-mud repofl seria.

6756 Federal Register 64943 et seq. @ec. 13, 1991).
Chapter 2-Safety of Aging Nuclear Plants 159

quire approximately 200 person-years of utility

effort (supplemented by unquantified consultant

support) and span 3 to 5 calendar years at a cost

of about $30 million.68

Under the license renewal rule, an applicant

must perform an integrated plant assessment

(IPA), analyzing all mechanisms that result in age

degradation, even for short-lived SSCs that are

routinely replaced. For degradation identified as

ARDUTLR, the utility must demonstrate a program to monitor or control that degradation. This

plant-specific assessment is intended to guide the

licensee through a structured process in order to

demonstrate that aging degradation of plant SSCs

has been identified, evaluated, and addressed, and

to ensure that the licensing basis will be maintained throughout the renewed license term.

As discussed in detail in chapter one, there are

some practical problems with implementing the

rule and its accompanying statement of considerations (SOC). These involve such issues as the

level of detail required in the IPA, problems with

key definitions (e.g., ARDUTLR as defined has

little practical meaning), and consistency with

other aging management requirements (e.g., the

maintenance rule). As discussed in chapter one, the

NRC is considering revising the rule or specifying

a simplified implementation process.69

No plant has yet submitted a license renewal

application. Owners of the Yankee Rowe and the

Monticello plants originally planned to submit

license renewal applications in 1991 as part of a

jointly funded, multiyear DOE/industry leadplant program. However, poor economics, including the costs of answering questions about the

safety of their RPV, prompted Yankee Rowe’s

owners to opt for early retirement in late 1991. In

late 1992, Monticello’s owner indefinitely deThe operating license for the Fort Calhoun Station

expires in 2008. Recapture of the construction period

could allow 5 years additional operation before

license renewal would be required.

ferred its renewal application, citing concern

about the interpretation of NRC’s rule, noting that

the number of systems to be reviewed had grown

from the original 74 to 104 with “no indication of

where it might go from there. ’70 Also noted were

concern over operational cost increases and about

DOE’s ability to accept spent fuel. Finally, in late

1992, the Babcock and Wilcox Owners’ Group

announced its intentions to pursue a joint effort in

developing a license renewal application. Other

owners’ groups are pursuing similar efforts.

License renewal has implications for other

NRC safety requirements for specific plants. One

example is application of the backfitting rule.71

Although a plant’s CLB is supposed to be

adequate for protecting the public health and

safety, the backfitting rule allows additional

requirements when certain conditions are met.

Specifically, the rule allows such additional

requirements if a backfit analysis shows that there

@ U.S. NUCIW Regulatory cotissio~ Regulatory Analysis for Final Rule on Nuclear Power Plant License Renewal, NUREG-1362

(Washington+ DC: October 1991), table 4.6.

69 us. Nuclear Re@atO~ Co~5sio% SKY-93-1 13, Apr. 30, 1993; and U.S. Nuclear Regulatory Cotissioq SE~-93-049t ‘U. 1*

1993.

70 Jfi Howmd, chef Executive Officer of Nofiem S@tes power cit~ ~ N~cieonics week, VO1 33, No. %, NOV. 12, 192, pp. 12, 13.

71 1* cm 50109.”
60 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Box 2-G--Systematic Assessment of Licensee Performance and

Other Performance Indicators

The Systematic Assessment of Licensee Performance (SALP) program is an integrated effort to assess how

well a given licensee directs and provides the resources necessary to provide the requisite assurance of safety.

The purpose of these NRC assessments is to direct better both the NRC and licensee attention and resources

at a facility to those safety issues requiring the most attention. Some in the nuclear industry, however, have

suggested that the SALP process is subjective and not factually supported.’

The SALP assessment includes reviews of licensee event reports (LERs), inspection reports, enforcement

history, and licensing issues. These ratings are a subjective summary of the performance of the licensee in each

functional area New data are not necessarily generated in the conduct of a SALP assessment. The SALP

assessment rates performance in selected functional areas: plant operations, radiological controls, maintenance

and surveillance, emergency preparedness, security, engineering and technical support, and safety assessment

and quality verification. SALP rating categories are the following:

1:

2:

3:

N:

This rating designates a superior level of performance where reduced NRC attention maybe appropriate.

This rating designates a good level of performance where NRC attention should be maintained at normal

levels.

This rating designates an acceptable level of performance where the NRC will consider increased levels

of inspection.

insufficient information exists to support an assessment of licensee performance.

NOTE: There is no failing gmda, but #anta not maatlng acceptalda Ievals (i.e., inadequate parformanca to receive a category 9 mting) are

b$d a “8hOW UMJSO” OKJM mdthg In thdr shutdown.

Since 1986 the NRC has also provided quantitative indicators of nuclear power plant safety performance. The

program currently provides seven performance indicators, including the average number of SCRAMS and the

equipment forced outage rate (see figures 2-4 and 2-5). These data are published and provided to NRC senior

managers on a quarterly basis, and each utility receives the reports for its plants. in contrast with the NRC SALP

program, which provides subjective evacuations of licensee performance, the performance indicators measure

well-defined, discrete events. However, the relationship between these indicators and expected public health and

safety impacts, while giving a sense of safety performance, is not definitive.

The Institute of Nuclear Power Operations (INPO) has also developed quantitative indicators of nuclear

performance. The INPO program includes such factors as plant capability factor, rate of unplanned automatic

scrams, collective radiation exposure, and industrial accident rates. in addition to publishing the indicators for

industry-wide performance, INPO has set goals for improving future performance that are intended to be

challenging but achievable.2

1 IJ.S. N~ear Rqldatory Commission, /r?c#ustry Percepflons of the hnpactofthe U.S. ~UCh3ar@Wk?~Ory

Comrnkdon on Nuolear Powr Plant Act/v/t/es, NUREG 1395 draft (Washington, DC: Maroh 1990), p. 13.

2 institute of N~ar pow~ xt~ns, “19$2 Performanm lndl~tors for t~ U.S. Nu~ear Industry,”

(Atlanta, GA: March 1993).
Chapter 2-Safety of Aging Nuclear Plants 161

Figure 2-4—Average Number of Reactor Scrams

While Critical

3.57

1987

2.27

—

1988

1.85

1.63 1.52

1989 1990 1991

SOURCE: U.S. Nuclear Regulatory Commission, 1991 A.nmM/Fbport,

NUREG-1 145, vol. 8 (Washington, DC: July 1992), p. 52.

will be a substantial increase (beyond adequate

protection) in the overall protection of the public

health and safety and if the implementation costs

warrant this increased protection. Because license

renewal extends a plant operating life, the safety

benefits estimated in the backfit analysis will

generally be greater than under the original

license term. The extent to which potentially

costly backfits will be required as a condition of

license renewal has not been determined.

HEALTH AND SAFETY GOALS FOR AGING

PLANTS

1 Public Health and Safety Goals for

Nuclear Power Plants

To address the issue of acceptable public safety

risks from operating nuclear power plants, the

NRC set formal, qualitative safety goals for plant

operations in 1986 after several years of developFigure 2-5--Average Equipment Forced Outage

Rate Per 1,000 Critical Hours

I 0.6

0.45 0.45

JI ~ r

1987 1988 1989

0.39

1990

--i

1991

SOURCE: U.S. Nuclear Regulatory Commission, 1991 Armua/Repurt,

NUREG-1 145, vol. 8 (Washington, DC: July 1992), p. 52.

ment. 72 The goals established by the NRC for

public and occupational health and safety for

existing plants do not change as the plants age.

The goals, which apply to existing as well as

future plants, are:

Individual members of the public should be

provided a level of protection from the consequences of nuclear power plant operation such

that individuals bear no significant additional

risk to life and health.

Societal risks to life and health from nuclear

power plant operation should be comparable to

or less than the risks of generating electricity by

viable competing technologies and should not

be a significant addition to other societal risks.

The NRC also set the following quantitative

objectives for risk of immediate deaths caused by

a radiological accident and for deaths from cancer

to be used in determining achievement of the

goals:

7251 Fe&ra[Regis&r 30028 et seq. (Aug. 21, 1986).
62 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Box 2-H--Environmental Qualification of Electrical Equipment

A wide variety of electrical cables from different manufacturers are used in nuclear power plants for

instrumentation and controls. Cables used in fossil-fuel power plants have generally performed well for as much

as 60 years, even though the materials used were inferior& newer cables.1 Cables used in nuclear plants have

a similar excellent operating history. However, aging degradation resulting from high temperature and radiation

may go undetected and result In inadequate performance under the additional environmental stresses of accident

conditions. Cables required to perform a safety function during and following a design basis event are required

to qualified considering the effects of aging.2

Institute of Electrical and Electronics Engineers (IEEE) standards adopted in 1974 and incorporated in NRC

requirements specify an environmental qualification (EQ) procedure involving accelerated aging of test samples

to ensure that aged cables perform adequately under accident conditions. 3 However, EQ testing of pre-aged

samples was not required for the more than SO plants receiving construction permits before June 1974, although

consideration of aging effects were to be considered in design. Cable testing and surveillance within a plant’s

containment is minimal, because they are often hard to access.

The NRC conducts an extensive, ongoing cable testing program at Sandia National Laboratories, which

examines a wide variety of cables.4 The results generally indicate that most popular cable types should perform

adequately during current plant operating license and any renewed terms, although there maybe some exceptions

requiring further analyses? Similariy, EPRI initiated a multiyear project in 1985 to compare natural and artificial

aging for a limited number of cable types.6 Initial results have found no changes in material properties of concern.

Overall, electrical equipment performance has been excellent, research results on cable aging have been

favorable, and EQ has not raised near-term concerns for plant operation, but both the NRC and the commercial

nuclear power industry continue to address some longer term issues. NRC staff, for example, recently proposed

re-examining the adequacy of current EQ requirements as a generic safety issue. 7 Among the issues that may

have long-term impacts are the following:

~ the accuracy of EQ methods involving artificial aging,

= the appropriateness of current EQ requirements for cables for which artificial aging tests were not required, and

s a lack of effective testing and surveillance methods to detect degradation.

1 A.S. Amar, et al., Reskwl Me Assessment of Major Light VW!W Reactor t%mponents~rvlsw

NUREG/CR-4731 (Washington, DC: U.S. Nuclear Regulatory Commission, November 1989).

210 CFR 5049.

3 iEEE 383-1974; incorporated in 10 CFR 50.49.

4 Sandb I+Jationai Laboratories, Aging, CondMonMonitor&?g, andLossofCcwkmtAcddent Tesfs ofCkWS IE

Ekctrka/ Cableq NUREG CR-5772, vol. 1-3 (Washington, DC: Nuclear Regulatory Commisdon, 1992).

5 For example, Sandia tests reoentiy Identified a potentiai defioienoy for -~fk Ma@ of -e*en

used aocording to its environmental quailfioation. A Thadani, U.S. Nuoiear Regulatory Commission, Memorandum

to Steven Varg~ Director, NRC Division of Reaotor ProJeots, Jan. 27,1993.

G university of Connecticut, /Vatu# Versus Artifioiai Agfng of Nuokar Power Plant Cqxmnts, EPRI

TR-100245 (Paio Aito, CA: EJeotric Power Researoh institute, January 1992).

7 U.S. Nuclear Regulatory Commission, SECY 93-049, Mar. 1, 1~.
Chapter 2-Safety of Aging Nuclear Plants 163

~ The risk to an average individual in the vicinity

of a nuclear power plant of prompt fatalities

that might result from reactor accidents should

not exceed one-tenth of one percent (0.1

percent) of the sum of prompt fatality risks

resulting from other accidents to which members of the U.S. population are generally

exposed.

■ The risk to the population in the area near a

nuclear power plant of cancer fatalities that

might result from nuclear power plant operation should not exceed one-tenth of one percent

(0.1 percent) of the sum of cancer fatality risks

resulting from all other causes,

These goals provide useful guidance in evaluating the adequacy of plant safety and in developing and implementing regulatory requirements.

There remain, however, some limitations to the

safety goal policy as it relates to plant aging and

to existing plants generally. Limitations to the

safety goal policy include the practical translation

of risk-based goals into regulatory activities, no

consideration of changing population characteristics near a plant, no discussion of the cost-benefit

analyses now used in safety decisions, and an

unclear relationship and consistency with safety

goals found in other Federal law.

Perhaps the greatest weakness of the safety

goal policy is the practical difficulty of translating

the risk-based goals into regulatory practices. The

relationship between many of NRC’s regulatory

activities and its safety goals is unclear. For

example, the safety goal policy is not mentioned

in the license renewal rule, the 32-page Statement

of Considerations accompanying the rule,73 or the

NRC’s regulatory analysis of the rule.74 Similarly, the most recent plan for the NRC Nuclear

Plant Aging Research (NPAR) program does not

reference the safety goal policy in any of its

75 One aging-related approximately 170 pages.

example of a regulatory effort explicitly incorporating risk issues is the maintenance rule, which

requires consideration of risk-significance in the

development of maintenance programs.76 The

NRC has an ongoing effort to make greater

application of the safety goal policy .77

A second limitation with the safety goal policy

is indirectly related to plant age: the changing

population characteristics over the life of a plant

are not addressed. When the safety goal was first

adopted, one NRC Commissioner noted that the

safety goals do not explicitly include population

density considerations; a power plant could be

located in Central Park and still meet the standard.78 Population density and other related demographic characteristics (e.g., transportation facilities) can all change over the decades a plant is in

operation.

Regarding the use of cost-benefit analyses, the

backfit rule allows the NRC to require safety

efforts that surpass those necessary for the adequate protection of public health and safety .79

These safety efforts must meet an economic test,

comparing costs with the expected benefits of

improved safety. This suggests a third limitation

with the safety goal policy, because it does not

address the appropriateness of mandating activities not necessary for adequate protection, or the

7J 56 Fe&ra/ Register 64943-64980 (Dec. 13, 1991).

14 U.S. NUCIW Rq@a@~ Commission Regulatq Analysis for Final Rule on Nuclear Power Plant License Renewal, NUREG-1362

(Washington, DC: October 1991).

IS U.S. Nucle~ Re@ato~ Commissio~ Nuclear Plant Aging Research (NPAR) Program plan, NUREG-1 144, Rev. 2 (Washingto~ DC:

June 1991).

7610 CFR 50.65(a)(3).

77 U.S. NUCIW Regulatory Commission “Interim Guidance on Staff Implementation of the Commission’s Safety Goal Policy,

SECY-91-270.

7851 Federa[ Register 30033 (Aug. 21, 1986).

7910 cm 50.109.
64 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

role of economic analyses in supporting those

requirements. This can be an important license

renewal issue, as the extended operating period

results in higher estimated benefits. Specifically,

license renewal may result in additional costs for

NRC-mandated back.tits not required for adequate safety.

A fourth limitation with the safety goal policy

is unrelated to plant aging but relevant to determining the adequacy of the goals: indications of

consistency with safety goals found in other

Federal law. Nuclear power plants are not unique

among electricity supplies in imposing public

health and safety risks. Production and use of

fossil fuels contribute to health problems ranging

from respiratory disease related to particulate

and sulfur oxides, to cancers associated with

carcinogenic releases from petrochemical facilities, to fatal accidents in the mining and transportation of coal.80 Heavy use of fossil fuels also

produces substantial CO2 emissions, which contribute to the chance of potentially catastrophic

public health and safety impacts resulting from

global environmental change. Even energy efficiency measures can create public health and

safety risks. For example, better sealed houses

can result in indoor air quality problems, such as

increased radon exposures. Although the NRC

safety goal suggests comparing nuclear plant

risks to the risks of other generating sources, a

belief that “the absence of authoritative data

make it impractical to calibrate nuclear safety

goals by comparing them with coal’s risks based

on what we know today, ’ led the NRC to omit

quantitative objectives for explicitly assessing

that portion of the goal.81

@ The Impact of Aging on the Attainment of

Safety Goals

The best available evidence indicates that

NRC’s public safety goals are met with wide

margins, and should continue to be met as plants

age, assuming effectively designed and implemented maintenance programs and continuing

research to identify latent aging effects. There will

always remain some risk and uncertainties, however, and continued nuclear industry and Federal

regulatory vigilance remains crucial to implement

current practices and to revise them as necessary.

Regardless of plant aging effects, the public

cancer risk from normal nuclear plant operation

appears very low relative to the NRC goal. Aging

management activities, such as equipment replacement and other maintenance work, are

primarily contained within a plant.82 According

to the NRC, these activities are unlikely to alter

the offsite radiation exposures currently experienced. 83 The estimated public radiation doses

from nuclear power plants are extremely low—

very far below the allowed maximum.84 In part,

estimated public doses are far below regulatory

ceilings, because of an additional regulatory

requirement to limit exposures to “as low as is

reasonably achievable” (ALARA).85

In 1988, the estimated average annual dose for

a member of the public residing near a nuclear

go U.S. Enviro~en~ Protection Agency, Oftlce of Air ~d mdiation, ‘‘Regulatory Impact Analysis on the National Ambient Air Quality

Standards for Sulfur Oxides (Sulfur Dioxide),” draft May 1987, chapters 6 and 7.

8151 Federul Register 30030 (Aug. 21, 1986).

82 Eveq nUCIW Plmt relea~5 some mdionuctides during normal operations to which the public -y h exposed. (Some cod Power P~@

also release some radionuclides, depending on impurities in the coal.)

S3 U*S, NUCIW ReW~toV co~ssio~ EnVjron~ntaI ASseSS~nf for Final Rule on Nuclear power Plant k“cense Renewal ,

NUREG-1398 (Washington DC: October 1991), p. iii.

S4 Be-g ~ 1994, me m~m~u~ expos~e limit for a member of tie pubtic tiving n~ anuckarphmt is lowered ftOm 500 tO 100

mrem, still thousands of times higher than estimated maximum exposures. 10 CFR 20. 1301(a).

85 ALARA involves ‘‘taking into account the state of technology, and the economics of improvements in relation to benefits to the public

health and safety, and other societal and socioeconomic considerations, and in relation to the utilization of atomic energy in the public interest. ’

10 CFR 20.l(C).
Chapter 2-Safety of Aging Nuclear Plants 165

plant was about 0.001 mrem.86 This dose represents a very small fraction of the total exposure

from all sources, including natural ones such as

cosmic rays or radon-bearing granite (figure 2-6).

The best available evidence indicates that the

excess cancer risk to the public from operating

nuclear power plants is less than 0.00003 percent,

over three orders of magnitude below the safety

goal of 0.1 percent additional cancer mortality

risk.87 There are uncertainties in estimating health

impacts for any level of radiation exposure (box

2-I). If, however, future exposures and risk remain

even remotely similar to past experience, the

safety goal should be readily met.

With regard to accident risks, the best available

information, although inherently uncertain, indicates that if aging is properly managed the risk of

fatalities resulting from a severe nuclear power

plant accident in the United States is low relative

to the NRC safety objective. For example, the

NRC's best and most detailed estimates indicate

that an individual near a nuclear plant faces a risk

from a plant accident of less than 0.02 per million

(figure 2-7).88 In contrast, the accidental death

rate in 1990 from non-nuclear accidents for the

U.S. population was about 370 per million

people, or over 18,000 times higher.89 Thus, the

NRC’s safety objective for prompt fatality risk

appears met by at least a factor of about 18.

Figure 2-6—Average Annual Background Radiation

Exposure, U.S. Population (360 millirems)

Other 1%

includes nuclear

Radon 55%

plant operations

_-”-’ (0 ”030/0) KiR$s& \ Medical x ray 11 ‘/0

Cosmic 8%

SOURCE: National Research Council, Hea/fh Effects of Exposure to

Low hwe/s of /onizhg Hadaflon BE(R V (Washington, DC: National

Academy Press, 1990), p. 19.

For context, consider the accidents at Three

Mile Island (TMI) in 1979 and at Chernobyl in

1986, neither of which was related to power plant

aging. At TMI, there were no immediate fatalities,

and the best estimate of resulting cancer fatalities

over the next several decades is zero. 90 Despite a

partial core meltdown, there was no containment

86 The es-ted ~imm ~~ dose r~iv~ by any member of the public in 1988 was 0.02 mrem. D.A. Baker, Pacific Nofiwest

Laboratory, Popzdation Dose Commitnu?nts Due to Radioactive Releasesf?om Nuclear Power Plant Sites in 1988, NUREG/CR-2850, VO]. 10

(Washington DC: U.S. Nuclear Regulatory Commission January 1992), pp. i~ 1.4-1.5.1988 is the most recent year for which estimated

exposures were readiiy available from the NRC. Radiation monitoring systems at various locations within and around each plant are used, but

radiation levels beyond plant boundaries are often too low to register sufficient information about the exposure of neighboring populations.

Therefore, annual exposures for neighboring populations within 50 miles of power plants are estimated based on kaown releases. Tom Essig,

OffIce of Nuclear Reactor Regulatio@ U.S. Nuclear Regulatory Cornmissiou personal communication Feb. 18, 1993.

ST For ~ mud Me~e dose of 100 rnrerq the best estimate of excess cancer mortality is abOut 3 ptXCeIM. Cotitiee on the Biological

Effects of Ionizing Radiations, National Research Council, Health Effects of Exposure to LQW Levels of Ionizing Radiation: BEIR V,

(Washington+ DC: National Academy Press, 1990), pp. 172-173. Assuming a linear dose-response relationship (which is necessarily uncertain),

an annual average exposure of 0.001 mrem then would produce a risk of excess cancer mortality of 0.00003 percent. If actual exposures

approached the maximum exposure Iirnit rather than ALARA, the best available information indicates that NRC’s safety goal would not be

met.

88 us, Nucleu Rq@@~ co~ssioq Severe ACci~enf Risks: An Assessment for Five U.S. Nuclear power PZUntS, NUREG-1 150, VO1.

1 (WashingtoXL DC: December 1990), p. 12-3.

as U.S. Bureau of tie Cemus, Statistical Abstract of the United States: 1992, 112th ed. (Was~oQ DC: 1992), p. 82.

90 J.1, Fab~t, “He~~ Effec~ of tie Nucl~ &cident at ThrM me Isl~d, ” Health phy~ics, VO1. A(), February 1981, pp. 155-156.
66 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Box 2-1-Estimating Health Impacts From Public Radiation Exposure

There are two principal approaches to determining the public health impacts of normal nuclear power plant

operations: 1)epidemiological studies comparing the health of populations living near plants to other populations,

and 2) risk assessment, which involves estimating accident probabilities and their consequences in order to

calculate exposure levels and health impacts.

Several epidemiological studies of public exposure from nuclear power plants and their health impacts have

been performed, but results have varied. Some studies found increased cancer incidence, while others actually

found decreased incidences.1 At present, there are no national data that indicate that current public exposures

to radiation from operating power plants produce detectable increases in cancer deaths.2 Epidemiological studies

of radiation cancer risks from nuclear power plants rarely, if ever, have enough information to provide complete

or conclusive results, because the risk is generally too low to measure and data needs can be substantial. For

example, researchers performing epidemiological studies must identify appropriate control populations, follow or

obtain data on the status of exposed populations overlong periods (generally decades), and obtain reliable data

on cancer incidences and deaths from both study and control populations. Gathering such information over wide

geographic areas is extremely difficult and requires an extended research commitment, in terms of both time and

funds. In addition, cancer caused by radiation cannot generally be distinguished from cancer caused by other

sources. This complicates efforts to identify sources of risk when there are detectable cancer increases in a study

population exposed to low levels of radiation.

Furthermore, as many epidemiological studies of populations exposed to the very low Ievels of radiation

associated with operating nuclear power plants have been inconclusive, current estimates of the radiation health

impacts of low doses are generally based on data from high exposures-such as the atomic fallout from the 1945

bombing of Japan. These data are generally extrapolated linearly to estimate the risks of lower radiation doses,

such as those experienced by residents near nuclear power plants. However, there are substantial uncertainties

in extrapolating risk estimates from high doses to low doses.3 In particular, risk may not have a linear relationship

relative to dose but may, in fact, decrease below a certain dose threshold. On the other hand, the opposite may

be true, and risks are Iikely to vary depending on other factors such as the age and health of a population. Thus,

risk assessments based on linear dose-response relationships remain inherently uncertain.

1 SW, fore~m~e, committee on the Biological Effects of ionizing Radiations, National Research Coundl,

Hea/th Effects of E~sure to fowhwekoflorking Radiatkm:/3E/R V(Washington, DC: National Academy Press,

Iggq, pp. 377-379; and S. JabIon, Z. Hrubeo, J.D. Boice, Jr., and B.J. Stone, National Cancer Institute, Can@r/n

Pophtlons L/vhg hkwNuckar Fad/ities (Washington, DC: U.S. Government Prtnting Office, July 1990), vol. 1,

Report and Summary, pp. 8-15.

2 [nthis Oonteti, ac’detectable” Inorease is one that can be distinguished from the expeoted number of =Ws

in a population. See S. JabIon, Z. Hrubec, and J.D. Boice, Jr., “Cancer In Populations Wing Near Nuclear Fadlitles:

A Survey of Mortality Natlonwtde and Inddence In Two States,” 7??e Journa/ofthe Anwkxm Medlca/Assodat/on,

Mar. 20,1991, vet. 265, No. 11, pp. 1403-1408.

3 SW, fW e~~e, ~mmitt~ on the Biological Effects of Ionizing Radiations, Nationat Research Coundi,

Health Effects of Eqxwre to LowLevels oflorkhg Radiation: BE/l? V(VVashington, DC: National Academy Press,

1990), pp. 1-s. As expl~ned in this source, risk projections for solid tumors are linear, while those for Ieukemias are

linear quadratic.
Chapter 2-Safety of Aging Nuclear Plants 167

Figure 2-7-Comparison of Probabilistic Risk Assessment Results With Safety Goals (per reactor year)

1 .OE-06 i

1.OE-07

i

!

1 .OE-08 -

{

1.OE-09

I

1.OE-1 O ,

‘ --- Safety goal Legend

~ 95 ”/0

l-l-Mean

Median

570

1.OE-05 T

i

“+

I

1 .OE-06 -—

.&’

i

~ 1.OE-07

A

z

CrJ

~ 1. OE-08

.-

,-

~

—

—

1.OE-09 I

Safety goal

n

SOURCE: U.S. Nuclear Regulatory Commission, Severe Acctient Risks:An Assessment for /%e U.S. Nuclear Power P/ants, NUREG-1 140, vol.

1 (Washington, DC: Deeember 1990), p. 12-1.

breach at TMI, and the radiation released was

low. People living within 10 miles of the plant,

who experienced the highest estimated exposures, received an estimated average 6.5 milliems, a small fraction of the annual background

radiation level. No radiation levels above background were detected beyond the 10-mile radius

of the plant.

In contrast, the 1986 Chernobyl accident

caused widespread release of large amounts of

radionuclides and caused about 30 prompt fatalities--

most of them emergency workers. The best

estimate of resulting cancer fatalities is about

17,000, or about 0.01 percent above the background cancer fatality rate expected over the

remaining lifetimes for the affected European

population. The health risk to the population

living near the plant is much greater. About

24,000 of the 115,000 people evacuated from the

surrounding area received an average of 43 reins.

This dose is estimated to lead to an additional 26

fatal leukemias over their lifetimes, a risk increase of 200 percent for a group this size.91

The public risk from a nuclear accident depends on two factors: 1) the probability of a

severe accident with a substantial offsite release

of radiation, and 2) the consequences on the

exposed population, Unmitigated aging degradation, or other factors that change over time, can

affect both the probability of an accident and the

severity of the consequences. For example, the

probability of an accident involving a large

release of radionuclides depends on the frequency

of initiating events (e.g., human errors, equipment

failures, loss of offsite power) and the subsequent

events that might lead to reactor core and

containment damage. Inadequately managed, aging

degradation can increase the probability of equipment failure, thereby affecting both initiating

events and the ability to manage an accident.

91 M. Gol@ R. Ca@ and L. ~spaug~ Hea[th and Environntental Consequences of the Chernobyl Nuclear Power Plant ~cident,

DOE/ER-0332 (Washington DC: Office of Energy ResearcE U.S. Department of Energy, June 1987), pp. vii-xv.
68 [ Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Offsite conditions may also change over time,

such as changing population settlement patterns

around a plant, and thus alter the potential

consequences of an accident.

For decades, the NRC and the commercial

nuclear power industry have worked to understand better and quantify public accident risks. In

1975, the NRC completed a much criticized study

of the probabilities and consequences of severe

accidents at two commercial nuclear facilities

using PRA techniques for the first time.92 Following the TMI accident, the NRC commissioned

indepth PRAs of five nuclear plants representing

major U.S. reactor designs (Zion, Surry, Sequoyah, Peach Bottom, and Grand Gulf) .93 For

these “reference plants,” the NRC estimated

mathematical probabilities of complex system

failures and public health consequences. As

estimated in that effort, the risks are at least one,

and perhaps as many as five, orders of magnitude

below the current NRC safety goal. The reference

plant study did not explicitly address aging and

assumed that aging management programs were

sufficient to maintain current equipment performance.

Because small differences among otherwise

similar plants can create significant differences in

risk, the NRC in 1988 required all utilities to

conduct probabilistic studies of their own plants

called individual plant examinations (IPEs).94

IPE results were intended to improve the understanding of the types of severe accidents possible

at each plant and to ensure that no undetected,

plant-specific accident vulnerabilities existed.

Utilities are required to develop accident management methods for identified vulnerabilities.95

PRAs are subject to substantial uncertainties.

Commenting on the NRC PRA study of five

nuclear power plants, the Advisory Committee on

Reactor Safeguards (ACRS) noted that the “results should be used only by those who have a

thorough understanding of its limitations.”96

These limitations include the following:

■

■

■

limited historical information regarding the

failure rates of critical equipment, particularly

from aging effects;

the difficulty of modeling human performance

(e.g., the behavior of plant operators before and

during an accident); and

the lack of information regarding containment

performance.

The cost of performing PRA analyses can be

substantial; the NRC estimated that the IPE

program would cost operators an average of

between $1.5 million to $3 million per plant.

Despite their limitations, PRA methods can be

useful to identify risks and set priorities for

additional research and analysis. Utilities have

applied PRA methods and results to a variety of

operations, maintenance, and economic decisions.97

92 US. NUCl~Rq@tOry cOmSSiO~ReaCtOr s@epSt~nAsseSs~nt ofAccidentRisksin U.S. CommercialNuclear PowerPlants,

WASH-1400, NUREG-75-014 (WasbingtoU DC: October 1975); and U.S. Congress, Gftlce of ‘Ikchnology Assessrnen4 Nuclear Power in

an Age of Uncertain~, OTA-E-216, (Washington DC: U.S. Government Printing GflIce, February 1984), pp. 218-219. The NRC study was

initiated by its predecessor agency, the AEC.

93 U.S. Nuclear Regulatory CO- sioni Severe Acci&nt Risks: An Assessment for Five U.S. Nuclear Power Plants, NUREG-1 150, vol.

1 (Washington DC: December 1990). That analysis is reviewed in American Nuclear Society, ‘‘Report of the Special Committee on

NUREG-1 150, The NRC’s Study of Severe Accident Risks,” June 1990.

94 D*M, cmt~~~e]d, “~divid~ p~t Examination for Severe Accident Vulnerabilities, ” U.S. Nuclear Regulatory Commission+ Generic

Letter 88-20, Nov. 23, 1988; and U.S. Nuclear Regulatory Comrnissioa Individual Plant Examination: Submittal Guicknce, NUREG-1335

(widliIl@Om DC: August 1989).

95 U.S. Nuclear Regulatory COXId.$SiOn, “Integration Plan for Clostm of Severe Accident Issues,” SECY-88-147, May 25, 1988.

96 U.S. Nuclem Re@atory Commission Advisory Committee on Reactor &tfe@dS, htter to NRC ~Kemeth M. Carr, Subject:

Review of NUREG-1150, “Severe Accident Risks: An Assessment for Five U.S. Nuclear Power Plants,” Nov. 15, 1990,

97 Ywlkce Ato~c Elm~c Co., APPli~atio~ Of PM, ~~ N’P-7315 @J~o Alto, CA: Electric Power Research Institute, Mi3y 1991).
Chapter 2-Safety of Aging Nuclear Plants] 69

To address aging issues more directly, the NRC

NPAR program works to incorporate aging information into PRAs. Age-dependent PRAs model

the effects of maintenance practices and the

effects of aging on component failure rates, which

standard PRAs assume are constant. These studies indicate that aging can have a substantial

impact on reactor core damage if maintenance

programs are inadequate.98 However, agedependent PRAs lack sufficient data to determine

accurately aging effects on component failure

rates and the effectiveness of different maintenance practices. As a result, they remain an area

for continued analysis.99

Although accidents involving severe core damage are expected to be extremely rare (e.g., less

than once per hundred years in the United States),

there are actual operational experiences that can

complement PRA results. In particular, NRC’s

Accident Sequence Precursor program tracks

abnormal operating events 100 that could potentially lead to severe accidents.101 The program

uses PRA techniques to determine the significance of those events in terms of the likelihood of

core damage. In 1990, 28 operational events were

identified as resulting in probabilities of subsequent severe core damage of greater than one in

one million. The worst six of those events were

estimated to have core damage probabilities of

between 1 in 1,000 to 1 in 10,000 (figure 2-8).102

That is less, by a factor of between 1.7 and 18,

Figure 2-8—Accident Sequence Precursor

Quantities, 1984-1990

30

r

.—

Probability of an event resulting In core damage

u IE-6 ~ IE-4 ~ IE-2

25 ~ IE-5 _ IE-3

n

1984 1985 1986 1987 1988 1989 1990

SOURCE: U. S. Nuelear Regulatory Commission, 1991 Annual Report,

NUREG-1 145, vol. 8 (Washington, DC: July 1992), p. 52.

than would be expected based on a core melt

frequency of one per 10,000 years per plant.

I Occupational Health Impacts

Nuclear power plant workers are generally

exposed to more radiation than the residents

neighboring their respective plants. Whereas the

average member of the U.S. population is annually exposed to an effective total dose of 360

millirems (0.36 reins) from all sources,103 current

9S Science App~catio~ Internatioml Corporation, Evaluations of Core MeltFrequencyEffects Due !O ComponentAging and Maintenance,

NUREG/CR-5510 (JVashingtoq DC: U.S. Nuclear Regulatory Cornmissio~ June 1990); and U.S. Nuclear Regulatory Comrnissiow

Regulatory Analysis for Final Rule on Nuclear Power Plant License Renewal, NUREG-1362 (Washington DC: October 1991), appendix C.

99 Science Applications ktematiod Corporatio~ Approaches for Age-Dependent Probabilistic Safety Assessments with Emphasis on

Prioritization and Sensitivity Studies, NUREG/CR-5587 (Washingto~ DC: U.S. Nuclear Regulatory Commissio% August 1992); and A.P.

Domell, Jr., Sandia National Laboratories, “A Review of Efforts to Det ermine the Effect of Age-Related Degradation on Risk’

SAND91-7093, February 1992.

1~ Under 10 CFR 50.73, licensees must submit a Licensee Event Report (LER) when preestablished tits are exceeded or CC* evenw

occur. These reports serve as a primary source of operational event data. The threshold for reporting considers infrequent events of significance

to plant and public safety as well as more frequent events of lesser significance that are more conducive to statistical analysis and trending.

101 ()& Ridge Natio~ ~~ratoV, precur~or~ t. potential Severe Core Da~ge Accidents: 1990 A status Report, -G/CR-4674

(Washington DC: U.S. Nuclear Regulatory Commission August 1991).

IW US, Nucl~ Re@ato~ co~ssiom Annual Report 1991, -G-l145, VOI. 8 ~asti@ou DC: Jdy 1992), p. 54.

103 comi~ee on tie Biolo@~al Effects of ]ofiz~g Radiations, Nation~ Research Council, Hea/fh E’ects of Exposure to lbW ht?h Of

/onizing Radiation: BEIR V, (Washington DC: National Academy Press, 1990), pp. 18-19.
70 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

NRC regulations allow nuclear plant workers to

receive as much as 3,000 millirems (3 reins) per

calender quarter up to a limit of 5,000 millirems

(5 reins) per year, although ALARA goals encourage lower exposures.104 The average annual

measurable added radiation exposure for U.S.

nuclear plant workers in recent years has been

about 400 millirems.105 Individual exposures

vary, but few exceed the 5-rem limit. Between

1985 and 1989, only two of the approximately

210,000 monitored nuclear power plant workers

experienced doses exceeding 5 reins.106 

Increased maintenance activities associated

with aging can increase occupational exposures.

More frequent monitoring and testing of SSCs

can lead workers to spend additional time in areas

with concentrations of radionuclides. Major repairs also lead to additional exposures. For

example, the additional collective exposures resulting from replacing a steam generator has been

several hundred person-reins, the same order of

magnitude as typical annual plant exposures

otherwise occurring. However, for those plants

requiring them, steam generator replacements are

expected only once or twice over the life of a plant.

In 1991, the International Commission on

Radiological Protection (ICRP), an international

body established in 1928 to develop guidelines

for radiological health protection, recommended

reducing the accepted levels of occupational

radiation exposures from 5 reins per year to 2

reins per year, when averaged over a 5-year period

(i.e., a total maximum of 10 reins over a 5-year

period). The recommendation to limit the maximum occupational exposure in any single year to

5 reins was retained.107 Although the NRC

generally follows ICRP recommendations, an

NRC decision to comply with the 1991 ICRP

recommendation was postponed. As part of that

decision, the NRC cited recently reduced U.S.

occupational exposures from ALARA efforts to

levels that already approximate the recent ICRP

recommendations. 108

Although occupational radiation exposures are

carefully monitored, determiningg some of the

incremental health risks to workers is difficult.

For example, epidemiological studies of cancer

risk lack reliable data on the risks of whole body

radiation exposures below 10 reins (i.e., 10,000

millirems). 109 Nonetheless, the risk models in the

BEIR V report estimate that a working lifetime

exposure of 1,000 millirems annually (i.e., 1 rem

per year each year between the ages of 18 and 65,

or one-fifth the allowed maximum) will lead to an

increased cancer mortality rate of roughly 15

percent above expected levels.110

~~ 10 CFR 20.101. ~arwent mlex, the NRC decided to drop the quarterly limit. 56 Federal Register 23368, 23396 O@Y 21, 1991).

This rule will be effective in 1994.57 Federal Register 38588 (Aug, 26, 1992).

105 CT. ~d&~ ~d D. ~gemeyer, Occupatio~lRadiation Exposure at Commercial Nuclear Power Reactors and OtherFacilities: 1989,

Twenty Second Annual Repo~ NUREG-0713, vol. 11 (Washi.ngto~ DC: U.S. Nuclear Regulatory Commissio@ April 1992), pp. 3-4. Note:

The average measurable exposure differs from the average individual exposure, because not all nuclear plant workers show measurable

exposures. If all workers are considered, the average individual dose for commercial nuclear plant workers is much lower (about 200 millirems

in recent years).

1~ Ibid., p. 5-10. Beause 10 CFR Part 20 rules have allowed annual averaging, an individual exposure greater b 5 mms ~ my Yew wm

not automatically a violatiom as long as the age-adjusted annual average remained at 5 mm or less. Under new rules taking effect in 1994,

such averaging is no longer allowed, and 5 reins will be the maximum limit for each year.

107 ~tatio~ Codssion On RadiO@@l Protwtion, 1990 Recommendations of the International Com”ssion on Radiological

Protection, ICRP Publication 60 (New Yorlc Pergamon Press, 1991), pp. 72-73.

lm 56 Federal Register 23360, 23363 (May 21, 1991).

109 J,14 Fab~t, “He~~ Eff~~ of fie Nuc]e~ ~identat Three me Is~d,” Health Physics, February 1981, VO1. 40, p. 153. Note: ‘rhis

source actually notes 10 rads, but the units generally convert directly to reins on a 1:1 basis when considering gamma exposures, the exposure

of concern with commercial nuclear power.

110 co~~ee on tie Biolo@c~ Effec~ of ro~fig ~diatio~, National Resmch Council, Health Eflects of Exposure to bW &e/s Of

Ionizing Radiation: BEIR V, (lVashingtou DC: National Academy Press, 1990), pp. 172-173.
Chapter 2--Safety of Aging Nuclear Plants 171

According to one source, the 107,019 workers

exposed to the average 410 millirems in 1988 will

experience a risk of additional cancer deaths of

0.2 percent (two cases per thousand); the single

individual exposed to 6,100 millirems that year

will experience an additional cancer mortality

risk of 0.4 percent (four chances in one thousand). 111 As discussed earlier, however, there are

many uncertainties associated with such estimates, particularly assumptions about the validity

of transferring the results of high-dose exposures

to low-level exposures.

The comparative occupational health risks

between nuclear power and other energy sources,

particularly coal, may be worth examining in

more detail. Understanding these comparative

risks is important in evaluating the comparative

risk-benefits of any energy source. Although all

health effects, particularly deaths, are important,

there are data that indicate the comparative

occupational health risks associated with nuclear

power are low relative to other energy sources.

For example, the number of deaths and occupational injuries associated with coal production

may be far higher than nuclear energy production.112 OTA has not evaluated such claims for

this report, but evaluating the merits of commercial nuclear power plant life attainment and

license renewal requires a recognition, if not a

complete understanding, of these comparative

risks.

111 C.T. ~d~V~dD. Hagemeyer, OccupationalRadiation Exposure at Commercial Nuclear Power Reactors and Other Facilities: 1988,

Twenty First Annual RepoK NUREG-0713, vol. 10 (Washingto~ DC: U.S. Nuclear Regulatory Commission July 1991), p. 4-29.

112 J.I. Fab&t, “IS NWCleW Energy ArI UWceptable Hazard to Health?” Health Physics, September 1983, vO1. 45, No. 3, p. 576.
Economic

Lives of

Existing

Nuclear

Plants 3

A

11 power plants, nuclear and non-nuclear, will eventually

be retired. Each nuclear plant’s economic performance

(i.e., the cost of producing electricity while meeting

Nuclear Regulatory Commission (NRC) and other

safety requirements) plays a prominent role in plant life

decisions. The cost and availability of alternative resources is

also critical. Both the economic performance of nuclear plants

and the cost of alternatives are debated, changing, and highly

diverse. For this reason, economic life decisions are likely to be

determined over time, as individual conditions change based on

a host of separate decisions by utilities, State utility commissions, and Federal regulators. The cost of managing aging, while

potentially large for some plants, is only one aspect of economic

life decisions.

This chapter examines economic issues related to nuclear

power plants. The discussion centers on the following:

■ the changing context of the electric utility industry as it

relates to nuclear plant life decisions,

■ institutions involved and their roles in evaluating the

economic lives for existing nuclear plants,

■ the economic performance of existing nuclear plants, and

■ some factors affecting future nuclear plant cost and performance.

THE CHANGING ELECTRIC UTILITY CONTEXT

The electric utility industry is evolving rapidly. Pressures for

change started two decades ago with widely fluctuating fuel

prices, plummeting demand growth, hefty increases in the

construction costs of large power plants, and increased attention

to the environmental impacts of electricity generation. More

recently, supply competition and utility energy efficiency efforts

have increased markedly. These changes have reduced some of

I 73
74 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Figure 3-l—Electric Regions

Western Systems Mid-Continent Area

Coordinating Council Power Pool (MAPP)

(WSCC)

/ /

in the Contiguous United States

Mld-America

Interconnected

Network (MAIN)

<

— Northeast Power

Coordinating Coun

(NPCC)

Mid-Atlantic Area Council (M

Reliability Council

(SERC)

(ERCOT) - \ J+ \ .

Southwest Power ‘-”

Pool (SPP)

SOURCE: U.S. Congress, Office of Technology Assessment, E/ecttic Power Wheeling and Dealing:

Competition, OTA-409 (Washington, DC: U.S. Government Printing O!fice, May 1989), p. 159.

Twhnologid Considerations for Increasing

the costs of replacement power, placing additional economic pressures on existing nuclear and

non-nuclear plants. Increasingly, utilities and

their economic regulators are engaging in elaborate economic analyses and planning efforts

known as integrated resource planning (IRP) or

least-cost planning (LCP). The growing use of

IRP both addresses and contributes to the changing utility context, as discussed later.

In addition to change, electric market conditions across the Nation are diverse. The electric

power industry nationwide is subdivided by the

nine regions of the North American Electric

Reliability Council (NERC) (see figure 3-l), each

comprised of many individual, but interconnected, utilities that often form separate power

pools. 1 The U.S. electric power industry is a

diverse and complex arrangement of investor-and

consumer-owned utilities, government agencies,

and independent power producers. Regional differences in generation reserve margins, fuel mix,

and load growth reflect differing patterns of

population, climate, economic activities, and the

history of utility policy and regulation. One

overall indicator of these differences is the range

of regional values for replacement power, which

vary widely across the country (see figure 3-2).2

[cil

AAC)

‘ U.S. Congress, (3ft3ce of ‘lkchnology Assessmen4 Electric Power Wheeling and Dealing: Technological Considerations for Increased

Competition, OTA-E409 (Washington DC: U.S. Government Printing Office, May 1989), ch. 6.

Z J.C. Mm Kuiken et al., Replacement Energy Costs for Nuclear Elecrriciry-Generating Units, NUREG/CR-4012 (Washington DC: U.S.

Nuclear Regulatory Commission October 1992).
Figure 3-2—Diversity in Replacement Energy

Costs for Nuclear Power Within and

Among Regions, 1992

Chapter 3-Economic Lives of Existing Nuclear Plants 175

_ Plant with lowest replacement ~

energy costs in region

~ Plant with highest replacement energy costs in region

r-l

ECAR ERCOT MAAC MAIN MAPP NPCC SERC SPP WSCC

NOTE: These are estimated replacement energy costs for short-term

nuclear plant outages for 1992.

SOURCE: J.C. Van Kuiken et al., Flep/acernent Energy Costs for

Nuclear Electricity Generating Units, NUREG CR-4012 (Washington,

DC: U.S. Nuclear Regulatory Commission, October 1992), pp. 79-190.

These diverse factors can contribute to differing

prospects for existing nuclear plants.

As shown in figure 3-3, the use of nuclear

power differs greatly among U.S. regions. For

example, in 1991, nuclear power supplied about

77 percent of the electricity in the Commonwealth

Edison Co. (CECO) subregion of the NERC

Mid-American Interconnected Network.3 By contrast, there are no operating nuclear power plants

in the Rocky Mountain Power Area subregion of

the NERC Western System Coordinating Council.

~ Electricity Demand and Capacity Margins

Slack electricity demand and surplus generating capacity have been among the factors noted in

Figure 3-3—U.S. Regional Electricity

Supplies by Fuel, 1991

~ Other _ Hydro

D Oil/gas ~ Coal

m Nuclear

ECAR ERCOT MAAC MAIN MAPP NPCC SERC SPP WSCC

SOURCE: North American Electric Reliability Council, .EIecfrkity Supply and Demand 1992-2001 (Princeton, NJ: NERC, June 1992), pp.

44-60.

some nuclear power plant early retirement analyses. For example, owners of the retired Yankee

Rowe plant noted that a regional recession turned

a capacity constrained situation into one of excess

capacity, reducing the need for the plant. Similarly, Niagara Mohawk’s 1992 analysis of the

Nine Mile Point Unit 1 plant indicated for the first

time that early retirement might be economic, in

large part due to a substantially higher forecast of

the amount of non-utility generation available.4

However, that forecast is uncertain and based on

a now-repealed State law that provided a strong

economic incentive to non-utility generators. In

the case of the New York Power Authority’s

(NYPA) Fitzpatrick plant, NYPA’s chairman

noted that a planned non-utility generator was

uneconomical and unnecessary, but if developed,

J North American Electric Reliability Council, E/ectriciry Supp/y & Demand 1992-2001 (Princetom NJ: June 1992), pp. 44,46.

A Niagara MohawlG ‘‘Economic Analysis of Continued Operation of the Nine MiJe Point Unit 1 Nuclear Statio%’ Nov. 20, 1992; and R.R.

Zuercher, “Nine MiIe Point-1 May Be Next to Fatl to Unfavorable Nuclear Economics,” Nucleortics Week, vol. 33, No. 49, Dec. 3, 1992, pp.

1, 14-15.
76 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

The Fitzpatrick Nuclear Power Plant in New York is

among the plants that have reported facing increased

economic pressures.

it would result in a surplus of capacity, making

Fitzpatrick uneconomical.5

Nationwide, electricity consumption has continued to grow since the earliest nuclear power

plants began operation (see figure 3-4). However,

annual growth rates declined by nearly a factor of

three between the 1960s and the 1980s. Capacity

margins6 remain high in many regions, because

construction has been completed on plants begun

years earlier under assumptions of more rapid

growth (see figure 3-5). All but one of the nine

NERC regions plan to reduce capacity margins

over the decade.7 Still, utilities and the Energy

Information Administration (EIA) project that

substantial amounts of new generating capacity

(about equal to the total installed nuclear capacity) will be needed in most areas of the Nation

during this decade.8 However, much of this will

be for meeting peak loads rather than for the

baseload power supplied by nuclear plants. EIA

projects that existing capacity will be fully used

after 2000, and new baseload plants will then be

required.

As the sharp, unexpected declines in demand

growth between the 1960s and the 1980s demonstrated, predicting future demand can be highly

uncertain. The EIA projects that annual electricity

demand growth between 1990 and 2010 may

range from 1.3 to 1.9 percent.9 For context, even

the small divergence between these estimates

represents about 400 billion kilowatthours (kWh)

in the year 2010, roughly two-thirds the electric

output of all currently operating U.S. nuclear

power plants. Moreover, such broad national

averages may mask greater diversity and uncertainty at the regional level.

B Competitive Resources

The emergence of a variety of low-cost electricity resources has already altered the economic

outlook for nuclear power at several utilities. Two

particularly prominent developments have affected competition for existing nuclear plants: 1)

the increasing use of natural gas as a low cost and

convenient fuel for new electricity generation;

and 2) the recent surge in utility demand-side

management (DSM) efforts,10 a trend likely to

continue given the large, untapped potential for

SD. Airozo and R.R. Zuercher, “Gas Plant Competition Could Kill Fitzpatrick NYPA Chief Claims,” Nucleonics ~eek, vol. 33, No. 39,

Sept. 24, 1992, p. 8.

s Capacity margins are the fraction of generating capacity in excess of peak demand available to provide for emergency outages,

maintenance, system operating requirements, and unforeseen electricity demand.

7 North American Electric Reliability Council Electricity Supply and Demund 1992-2001 (Princetou NJ: June 1992).

8 U.S. Department of Energy, Energy Information Administration, Annual Energy Out/ook 1993, DOE/EIA-0383(93) (WashingtorL DC:

January 1993), p. 51.

9 ibid., p. 49,

10 For ~ ~dep~ &scussion of UUlity demmd-side management see U.S. Congress, Office of lkchnology Assessment 10m8Y Efickncy:

Challenges and Opportunities for Elecm”c Utilities, forthmming.
Chapter 3--Economic Lives of Existing Nuclear Plants 177

Figure 3-4—Electricity Sales, 1960-1991

3

I

I

/1

Y

. —7.1 O/. annual growth

+ ~ 2’0’Oann”a’grOMh-J

3.9Y0 annual growth

o ) I I 1 I r I I I 1 1 ! 1 1 1 1 I 1 ) I 1 , I ! 1 ) I I

196 0 1965 1970 1975 1980 1985 1990

SOURCE: U.S. Department of Energy, Annual Energy Review 7991, DOHEIA-0384(91), June 1992, p. 219.

highly economic energy efficiency improvements.11

In the decision to retire the Trojan plant,

Portland General Electric (PGE) assumed that

new low-cost resources, primarily DSM, would

be developed to replace the plant’s output.12

Notably, PGE’s analysis projected that DSM

could reasonably meet more than 10 percent of

the utility’s total energy requirements by the year

2012. Low-cost replacement power and prospective efficiency gains also played roles in the

economic analyses of the San Onofre Nuclear

Generating Station Unit 1 (SONGS-1).13 The

cost-benefits of needed capital additions at both

of these plants were diminished, in part, because

of determinations that gas-fired capacity and

energy efficiency would be more economic over

the long term. Similarly, in commenting on the

outcome of the 1989 early retirement of the

Rancho Seco plant, officials of the Sacramento

Municipal Utility District have noted that reliance

on natural gas and DSM have turned out to be

economic choices.

Competition from natural gas generation or

DSM has also been cited as challenging the

economic prospects of other operating nuclear

plants. For example, the operators of the Kewaunee plant determined that early retirement

and replacement with a new gas-freed plant may

be more economical than pursuing steam generator replacement in 1998, 15 years prior to license

expiration. 14 For both the Fitzpatrick and Nine

11 See U.S. Congress, Office of Technology Assessment, Building Energy Eficiency, OTA-E-518 (Washington, DC: U.S. Government

Printing Office, May 1992); and U.S. Congress, Office of lkchnology Assessment, Energy Eficiency in the Federal Government: Government

by Good Example?, OTA-E-492 (Washington, DC: U.S. Government Printing Office, May 1991).

[Z portland Gener~ Electric, 1992 Integrated Re.rource Plan, NOV. 12, 1992, p. 4A.3.

IS E Hfio, ~ $Sm onofre- 1 Shutdom Minks Era of ~ast.cost plans,” Nuc/eonics Weejq VO1. 33, No. 47, NOV. 19, 1992, p. 7; J.J. Wambld,

Manager of projects, Nuclear Engineering, Safety and Licensing, Southern California Edison Co., personal communication with OTA, Oct.

14, 1992; Portland General Electric, 1992 lntegrafed Resource Plan, Nov. 13, 1992, ch. 4a (Trojan Analysis).

14 D. Stellfox, “Riskof Premature Shutdown Grows; Kewaunee, Ft. Calhoun on Guard, ” Nucleonics Week, vol. 33, No. 36, Sept. 3, 1992,

pp. 1, I 1-12,
78 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

30

20

E

g

2

10

0

Figure 3-5-Current and Forecast Regional

Capacity Margins, Summer 1992,2001

_ 1992 ~ 2001

ECAR ERCOT MAAC MAIN MAPP NPCC SERC SPP WSC C

SOURCE: North American Electric Reliability Council, Hectriuty Supply & Demand 1992-2&21 (Princeton, NJ: June 1992).

Mile Point plants discussed above, the planned or

assumed nonutility generation capacity is expected to be fueled primarily by natural gas.15

Noting the option of new gas-fired combustion

turbines, Bonneville Power Administration has

indicated that if performance at the Washington

Public Power Supply System’s nuclear plant does

not improve within 2 or 3 years, it will consider

alternatives to its 300-megawatt (MW) stake in

the plant.16

Some analysts have raised questions about the

future availability and cost of natural gas supplies.

17 U.S. electric utilities plan to add more

natural gas-fired capacity than any other generating source in the next decade; the gas share is

expected to total 54 percent of the nearly 60,000

MW utilities plan to add between 1992 and

2001. 18 By 2010, according to EIA projections,

natural gas will generate more electricity in the

United States than nuclear power.19 Overall,

projections of future natural gas prices will

remain a subject of debate, and whether fixedprices available in long-term gas contracts will

remain low long enough to spur the early retirement of more nuclear units remains speculative.

Increasing competition in the electric power

industry from independent power producers and

wider transmission access are among the forces

affecting the cost of replacement power and, thus,

future plant economics.20 Independent power

producers, frost encouraged under the Public

Utility Regulatory Policies Act of 1978 (PURPA)21

and further encouraged by the Energy Policy Act

of 1992 (EPACT),22 have become a major force

in the electric industry and account for a rapidly

15 D. ~ozo ad R.R. Zuercher, “Gas plant Competition Could Kill Fitzpatrick NYPA Chief Claims,’ Nucleonics Wed, VO1. 33, No. 39,

Sept. 24, 1992, p. 8; R.R. Zuercher, “Nine Mile Point-1 May Be Next to Fall to Unfavorable Nuclear Economics,” Nwleonics Week, vol. 33,

No. 49, Dec. 3, 1992, pp. 1, 14-15.

lb ~thprove NUCIW Ufit pefiomace or Shut it DOW BPA ‘lklls WPPSS,” Electric utility Week, MY31) l~3J P“ 4“

17 NO*~~mEl~~cRefiabili~ co~cil, Relia&li~ Assess~nt 1$)$)2-2001”: The Fufure of Bulk JHeefric supply in No~h Am”ca

(Princetoq NJ: September 1992), pp. 26-28; T Moore, “Natural Gas for Utility Generation” EPRIJournal, vol. 17, No. 1, January/February

1992, pp. 5-1o.

16 NOW ~~ca Elec~c Reliabfiity Council, Elec.~ici~ Supply & De~nd ]$)gz-z~l: Sm)))q of Electric utility Supply & Demand

Projections (Princeton: June 1992), pp. 94, 101-107.

19 EM Projects tit na~~ gm w gen~te about 18 percent (or 735 billion kilowatthours), ~d nUCletU pow= but 15.5 pem~t (or 636

billion kilowatthours), of U.S. electricity in 2010. These figures reflect the EIA reference (business-as-usual) case. U.S. Departmen t of Energy,

Energy Information AdministratioRAnnual Energy Outlook 199-?: With Projections to 20)0, DOQEIA-0383(93) (Washington+ DC: January

1993), p. 49.

20 U.S. CoWess, Offlce of I&bnOIO~ Assessment, Electric Power Wheeling and Dealing: Technological Con.rideran”ons for Increased

Competition, OTA-E-409 (Washingto~ DC: U.S. Government Printing Office, May 1989).

21 pubfic u~i~ Re@atoq Policies Act of 1978, F%blic Law 95-617, NOV. g, 1%’8.

22 me Energy policy &,t of 1992, Public hW 102-486, Gd. 24, 1992.
Chapter 3-Economic Lives of Existing Nuclear Plants 179

growing share of new generation. Many States,

utilities, and the Federal Energy Regulatory

Commission (FERC) have sought to promote

competitive bidding and independent power production.

H Addressing Environmental Concerns

As with many industrial activities, electricity

generation can cause major environmental impacts. Increasing attention to the environmental

impacts of both fossil fuel combustion and

nuclear generation creates a source of substantial

uncertainty in future electricity markets. With

respect to nuclear plant economics, two different

types of environmental impacts are relevant:

1. the environmental benefits of reducing fossil fuel use, and

2. the environmental costs imposed by nuclear

power plants.23

Utility IRP often includes scenarios investigating

the impacts of such prospective environmental

costs. In general, estimating and applying the

economic costs associated with different types of

environmental impacts is highly complex, remains a subject of substantial debate, but is a

rapidly evolving field.24

Two major environmental concerns related to

fossil fuel combustion may improve the relative

economic attractiveness of existing nuclear

plants: global climate change and acid deposition. 25 All fossil fuel power plants produce carbon

dioxide (CO2), a gas that many experts believe

may contribute to severe global climate change if

not controlled in coming decades.26 U.S. CO2

emissions represent about 20 percent of total

annual global emissions, with electric utilities

responsible for about one-third of this amount. In

a recent report, OTA estimated that under present

conditions the annual carbon emissions from U.S.

electrical utilities to the Nation’s total could

increase to as much as 45 percent by 2015.27

Predicting what future efforts will be taken to

address CO2 emissions remains speculative. However, efforts to control these emissions could have

profound impacts. For example, consider a hypothetical $100 per ton carbon tax, which one

Congressional Budget Office study estimated

could potentially reduce CO2 emissions between

zero and 25 percent from current levels over a

10-year period .28 Such a tax alone would translate

into approximately $0.03/kWh for coal-fired

electric generation, more than the average operational costs at existing nuclear power plants. The

prospective cost of controlling CO2 emissions is

increasingly being considered in IRP. The resulting impacts can determine the economic attractiveness of a plant. For example, in its analyses of

early retirement for the Trojan nuclear plant, PGE

examined CO2 tax scenarios of $0, $10, and $40

per ton.29 While the analyses showed that a high

CO2 tax would make continued operation the

23 TheNRC’S env~omen~ assessment of the ]icense renewal rule discussed the costs of continued nuclear plant operation. U.S. Nuclem

Regulatory Commissio~ Environmental Assessment for Final Rule on Nuclear Power Plant License Renewal, NUREG-1398, October 1991.

B see, ~-.g., Pace u~versiv Center for Env~nrnental hgal Studies, Environmental COStS of Elec~ici~ (New Yor~ ~: Oceana

Publications, 1990).

25 Oher resomces, such as renewab]e energy and energy efficiency measures, do not produce COZ emissions ~d would d50 have relatively

improved economics. Natural gas and petroleum-fired generation produce about half the COZ per unit of electricity as does coal and could be

affected as well. The dominant role of coal, which supplies 55 percent of the Nation’s electricity, makes it likely that aggressive action to control

COZ emissions would affect all aspects of the electricity market.

26 See, genera~y, J.B. smith and D. Th@c (eds.), OffIce of policY~ pl arming and EvaluatiorL U.S. Environmental Protection Agency, The

Potential Effects Of Global Climate Change On The United States, EPA-230-05-89-050 (Washington DC: December 1989).

27 U,S. Conue,s, office of Tec~oloa Assessment, c~anging by Degrees: steps to Reduce G~eenfioUse Gases, OTA-O-482 (Washingto~

DC: U.S. Government Printing Office, February 1991), pp. 3, 25.

28 U,S. Con9eS5, Con9es5io~ Budget C)fflce, Carbon Charges as a Response to GIobul wa~ing: The Effects of Toing Fossil Fuels

(Washington, DC: U.S. Government Printing Office, August 1990).

29 A ~ of $4,0 pfl ton of C02 1S ~UiVFdent tO a &LX of $147 per ton ‘f c
80 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

most economic option, PGE viewed that future as

having a low probability of occurrence.30

Fossil-fired power plants are also responsible

for sulfur dioxide (SO2) and nitrogen oxide (NOx)

emissions leading to acid deposition. SO2 emissions and acid rain have serious, but generally

local or regional, effects: surface water acidification, fish losses, forest damage and decline,

materials and cultural impacts, reduced visibility,

and both direct and indirect human health effects.31 Of the estimated 23 million tons of SO2

emitted in the United States in 1987, over

two-thirds stemmed from electric utilities.32

Electric utilities are also responsible for about

one-third of the 18.6 million tons of NOX emitted

annually in the United States.33 The NOX controls

and SO2 emission ceilings and emission

trading provisions of the Clean Air Act Amendments of 1990 (CAAA)34 may have large but still

unclear economic impacts on some existing coal

plants. 35

In contrast to the environmental challenges of

fossil fuel combustion involving large volumes of

SO2, CO2, NOX, and coal ash, unique environmental challenges of nuclear plants involve relatively small volumes of materials with sometimes

high levels of radioactivity. Although most of the

volume of radioactive waste from nuclear plants

contains very low levels of radioactivity, handling, managing, and disposing all radioactive

waste from nuclear plants can be difficult and

costly. One potential environmental cost of nuclear plants that has been raised in IRP, in

addition to waste disposal, is the low probability,

but high consequence, risk of a nuclear plant

accident. For example, as part of its IRP, PGE

estimated the expected environmental costs associated with nuclear plant accidents to be between

zero and about one-half cent per kWh.36 This

estimate assumed that the maximum amount of

potential damage is no more than $35 billion,

several times more than the approximately $7

billion liability limit set by the Price Anderson

Act.37 For conservatism, PGE assumed the risk to

be 1/1000 per reactor year of operation. Others

have estimated both higher and lower expected

environmental costs. For example, a Pace University Center for Environmental Legal Studies

report estimated a cost of about 2.3 cents/kWh38

,

while one study for Yankee Atomic Electric Co.

estimated a cost nearly three orders of magnitude

less. 39

There are other environmental impacts with

less sweeping national implications that may

have important impacts on plant economics. All

nuclear and fossil steam power plants can raise

the temperature of the local cooling water used,

producing thermal plumes and altering oxygen

demands, both of which can affect aquatic life

near power facilities. For example, one analysis

so portland Gener~ Electric, 1992 Inregrared Resource Plan, NOV. 13, 1992, p. 4A.3.

31 National kid pr~ipi~tion Assessment Program, 1990 Integrated Assessment Report (Washingto~ DC: November 1991).

32 Ibid., p. 198.

33 Based on an esti~te for 1985. National Acid Precipitation Assessment Program, 1989 Annual Report of the National Acid Precipitation

Assessment Program (Washington, DC: June 1990), p. F-43,

34 cl~ Afi ~t ~en~ents of 1990, ~blic ~~ 101.549,Nov. 15, 1990, Tide IV,

35 U,S. Dep~ent of Ener~, Energy ~omation A-sEatio& Annul Outlook for u.S. Electric Power ]99]: Projections Through

2010, DOE/EIA-0474(91) (Washingto~ DC: July 1991), p. 25.

36 III additiou other external nuclear environmental costs associated with waste diSpOSzd, mutke OpemtiOnS, and fiel mining and

processing were estimated to total about 0.15 cents/kWh. Portland General Electric, 1992 Zwegrated Resource Plan, Nov. 13, 1992,

app. 7.

3742 uSC 2208 et. seq.

38 pace u~versi~ Center for Environmental Izgal Studies, Environmental COStS of Elecm”city, 1990.

39 EneIgYReSWChGIOUP, ~C., ‘‘Environmental Externalities and Yankee Nuclear Power StatiorL’ November 1991, as reported in Portland

General Electric, 1992 Integrated Resource Plan Nov. 13, 1992, app. 7.
Chapter 3-Economic Lives of Existing Nuclear Plants 181

of the impact on the marine environment from

operation of SONGS-1 estimated an economic

loss of about $6 million annually.40 Coal plants

produce vast volumes of ash, which is often laced

with heavy metals and radionuclides. Hydropower, the major renewable source of electrical

energy currently used in the United States, can

also have major impacts, mainly by flooding large

areas and causing perturbations in stream flows,

fish migrations, water temperatures, and oxygen

levels.

INSTITUTIONAL ISSUES IN NUCLEAR PLANT

ECONOMIC LIFE DECISIONS

The objectives in nuclear plant life decisions

stem from broader electric power system objectives, including the following:

assuring adequate supplies to meet demand;

minimizing the costs of electricity (including,

increasingly, environmental costs);

equitably treating both electricity consumers

and plant owners in the recovery of costs; and

increasingly, responding to intensifying market

forces in the electric power industry.

Responsibility for the economic performance of

existing nuclear power plants lies with the utilities owning and operating them.41 So, too, does

the ultimate responsibility for economic decisions regarding nuclear power plant lives.

Industrywide groups such as the Nuclear Management and Resources Council (NUMARC), the

Institute of Nuclear Power Operations (INPO),

the Electric Power Research Institute (EPRI), and

the Edison Electric Institute (EEI) address issues

related to plant economies as well. For example,

INPO, NUMARC, EEI, and EPRI are participating in an “Industrywide Initiative’ to improve

nuclear plant economic performance.

4 2

NUMARC’s principal role is to identify and

eliminate unnecessary or inefficient NRC regulatory activities leading to unnecessary costs .43 EEI

is helping utilities address economic regulatory

issues, including application of IRP. EPRI’s

principal role is to assist utilities with the

application of proven technology to reduce costs

and achieve benefits in plant reliability, productivity and thermal efficiency. In addition, EPRI is

continuing its two decade research effort to

develop more economic technologies for safe

operation and maintenance (O&M) of existing

nuclear power plants.44

All but about 8 of the 107 operating nuclear

plants in the United States are primarily owned by

investor-owned utilities and fall under FERC or

State economic regulation.

45 For these plants,

economic decisions are typically made by the

plant owners in conjunction with the respective

40 c~lfomla public uti~ties Commissio% Division of Ratepayer Advocates (CPUC DRA), ‘Report on the Cost-Effectiveness of Continued

Operation of the San Onofre Nuclear Generating Station Unit No. l,” Investigation 89-07-004, Sept. 25, 1991. According to CPUC DRA staff,

revised cost estimates of marine damage indicate that the cost is higher, on the order of $15 million annually. Robert Kinosim CPUC Division

of Ratepayer Advocates, letter to the Office of THmology Assessment, Feb. 8, 1993.

41 NWIY IMlfof tie 108 oprating nucleti power plants are jointly owned by hvo or more utilities. The remainder are solely owned. In tot~,

over 130 utilities have some share of existing plants. R.S. Wood, U.S. Nuclear Regulatory Commissio@ Owners of Nuclear Pow’er Plants,

NUREG-0327, Rev. 5 (Washington, DC: July 1991). For those, economic decisions are shared by the owners.

42 { ‘EEI TO Help Nuclear Move Ahead in Changing power Marketplace, ’ Nucleonics Week, vol. 34, No. 25, June 24, 1993, pp. 1,12-13.

43 Nuc]e~ -gement and ResoUces Council, Review of Operations and Maintenance Costs in the Nuclear IndustV, NUMARC 92-03

(Washington DC: December 1992), pp 54-56.

44 see, ~.g,, Grove En@Wfig, kc,, ~n8.Te~ Capital planning Con~iderin8 Nuclear Plant Life-cycle Management, EPRI T’R- 101162

(Pato Alto, CA: Electric Power Research Institute, September 1992).

45 Five of tie Natlon>s 108 operat~g DUCIW power plants are pubficly owed (e.g., by apubfic power authority or llllld Cooperative). ThKX

others are owned by the Iknnessee Wiley Authority (TVA), and are not subject to FERC or State economic regulation. TVA also has two

previously operating units with full power licenses under review (Browns Ferry 1 and 3), Many public power utilities also share joint ownership

of existing nuclear plants operated by investor-owned utiiities.
82 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

economic regulatory bodies.46 While economic

regulatory activities vary greatly by State, many

States play a strong role in promoting and applying

economic analyses to utility investment and

retirement decisions. For example, many States

require their respective utilities to perform IRP.

The public also has a role in the regulatory

activities related to plant economics. For example, the definition of IRP in the Energy Policy Act

of 1992 (EPACT) specifically requires including

public participation and comment in development

of the plan.47 The public may also raise economic

issues in NRC licensing actions. For example,

following the request of Pacific Gas and Electric

Co. (PG&E) to extend the license expiration dates

for the Diablo Canyon nuclear plants by recapturing the plants’ construction periods (see ch. 2),

one public interest group and the State of California received NRC approval to intervene in the

case.

48 The opposition was not related to plant

safety, but rather to a concern that extended

operation would increase electricity rates and

harm the State’s economy.

B Integrated Resource Planning and

Nuclear Plant Economic Analyses

Nearly all States that regulate nuclear utilities

require IRP already and all will eventually

consider its use, as required by EPACT.49 EPACT

also requires the Tennessee Valley Authority to

perform LCP in making resource decisions.

While IRP is not necessarily directed at examining nuclear plant life decisions, it can and has

been. For example, PGE’s decision to retire the

Trojan nuclear power plant was examined and

supported in PGE’s 1992 Integrated Resource

Plan, a planning exercise required by the Oregon

Public Utilities Commission.50 Also, the New

York Public Service Commission has required

regulated utilities in the State to examine the

economics of continued nuclear plant operation.51

Change and uncertainty are hallmarks of the

electric utility industry’s planning challenge. For

this reason, planning methods generally consider

a range of possible scenarios rather than attempt

to forecast accurately inherently uncertain future

conditions. For example, in its analysis of the

economics of continued operation or early retirement for the Trojan plant, PGE examined a range

of natural gas prices, electrical demands, and

plant costs and performance. Depending on the

assumptions used, PGE’s probabilistic analysis

indicated a range of net present value of continued

operation between -$1.8 billion to +$ 1 billion (see

figure 3-6).52 This wide range of possible outcomes suggests that plant life decisions may

depend on highly uncertain factors.

Because many factors in economic analyses are

inherently uncertain, disagreements about appropriate decisions should not be surprising. Rather

than finding one clearly optimal choice, plant

economic decisions involve professional judgments that attempt to balance alternative choices

and their uncertain outcomes. Some have sug46 ~ some cases (e.g., utility holding companies), wonomic ~WhtiOn of lltiity p~o~ ce rests with both the State utility commission

and the Federal Energy Regulatory Commission. For a discussion of Federal and State jurisdiction% see U.S. Congress, Offke of ‘lkchnology

Assessment Electric Power Wheeling andDealing: Technological Considerations for Increasing Competition, OIA-E=W9 (Washingto% DC:

U.S. Government Printing Offlce, May 1989), ch. 2.

47 Energy policy Act of 1992, Public bW 102-486, Sm. 111.

48 Federal Register Feb. 2, 1993, pp. 6827-8.

49 fierm policy ~t of 1~, ~blic ~w 102.486, Sec. 111, See ~so, U.S. Cowess, ~ce of ‘l&hnology Assessment, Energy Eflciency:

Challenges and Opportunities for Elecm”c Utilities, forthcoming.

m pofil~d Gener~ Electric, 1992 Integrated Resource Plan, NOV. 131992.

51 see, for Cxmple, N&g~ Mo~w~ “Economic Analysis of Continued Operation of the Nine Mile point Utit 1 Nuclew S@OQ” Nov.

20, 1992.

52 me expwt~ v~ue of confiued operation was a 1oss of $~ ~fion in 1992 doll~s, ~sed on the estiated probabilities of different

scenarios. Portland General Electric, 1992 Integrated Resource Plan Nov. 13, 1992, p. 4A.5.
Chapter 3-Economic Lives of Existing Nuclear Plants! 83

Figure 3-6-Trojan Plant Economic Analysis Results

0.14

0.12

0.10

c 0.08

am

S 0.06

cL

0.04

0.02

0

-2000 -1500 -1000 -500 0 500 1000 1500

Replacement costs less Trojan costs ($million)

SOURCE: Portland General Electric, 1992 Integrated Resource Plan, Nov. 13, 1992.

gested that certain past State regulatory activities

leading to plant retirement reflected an antinuclear bias rather than solid economic analysis. For

example, commenting on IRP, one industry

leader argued that “the process is subject to

abuse, and extremely sensitive to bias, and that

the economic analyses for SONGS-1 and Trojan

plants were manipulated to retire these plants.53

Though any planning process involving the

complex and uncertain factors found in the utility

industry is subject to manipulation, past economic decisions provide no compelling evidence

of regulatory bias. In the Trojan case, for example, the utility itself determined that early retirement was the best option. In the SONGS-1 case,

the owning utility argued that continued operation would be economic, but declined to pursue a

proposal to place the risks and rewards of plant

costs and performance on the utility.

1 Treatment of Unrecovered Capital in Early

Retirement

There is limited precedence in the economic

regulation of the electric industry to guide the

financial treatment of capital invested, but not yet

recovered in rates, following the early retirement

of a plant. Similarly, there is little precedent for

the treatment of shortfalls in decommissioning

funds resulting from early retirement. This is true

for FERC as well as State regulation. For example, the only precedence for treatment of costs for

the retired Yankee Rowe plant were two 1988

decisions for plant abandonment. However, those

were plants canceled during construction, not

abandoned operating plants .54 Of the six recent

early retirement decisions, unrecovered capital

and decommissioning costs ranged from a few

hundred million dollars for most to over $4 billion

for one. Allowing a utility to recover its capital

costs in an early retirement is consistent with the

traditional regulatory approach in which the

prudence of the plant investment is determined

when the plant becomes operational. However, in

those retirement cases where plant performance

was poorer and costs were substantially higher

than originally anticipated, State PUCs may

consider whether the utility performed adequately

53 phi~lp Ba~e, “N@e~ power in 1992: A Year-End Review, ‘‘ remarks to The Energy Daily’s Annual Utility Conference, Dec. 10, 1992.

M “FERC Okays Yankee Rate Hike But Eyes ‘Prudence’ of Shutdo~” Nucleonics Week, vol. 33, No. 37, Aug. 6, 1992, pp. 4-5.
84 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

during the operating life of the plant and whether

some cost disallowances are warranted.

Anticipated regulatory treatment of decommissioning and historical plant costs can weigh in the

economic attractiveness to a utility of early

retirement. As with the application of IRP, some

have argued that State regulators’ treatment of

capital recovery in early retirement decisions for

the SONGS-1 and Trojan plants were intended to

‘‘encourage their acquiescence.” 55 SONGS- 1

was retired in 1993 after 26 years of operation

under an agreement between the California Public

Utilities Commission (CPUC) Division of Ratepayer

Advocates (DRA) and the owners of the unit

(Southern California Edison (SCE) and San

Diego Gas and Electric Co.). The agreement

provided the utilities full recovery of the remaining $460 million in capital costs over an accelerated 4-year period rather than the remaining 15

years in the licensed life. In addition, about $29

million that had been excluded from the utilities’

rate bases pending further review was returned to

the utilities.56 The utilities’ rates of return on the

$460 million during the 4-year recovery, however, was reduced from 12 percent to 8 percent.

Not all commissions have allowed recovery of

historical capital costs in early retirement decisions. Public Service of Colorado’s (PSCO) Fort

St. Vrain (FSV) plant is a case in point. The unit

was built with about $1 billion in joint funding

from PSCO, the Atomic Energy Commission, and

General Atomics Technologies. After beginning

commercial operation in 1979, the unique hightemperature gas reactor experienced major operational difficulties, including problems with the

control rod drive assemblies and the steam

generator ring headers, low plant availability

(about 15 percent), and prohibitive fuel costs.57 In

1986, PSCO, the Colorado Public Utilities Commission, the Colorado Office of the Consumer

Counsel, and other parties agreed to remove

FSV’s $600 million remaining capital costs from

the utility’s rate base. 58 However, the plant

continued to operate under a performance incentive rate, giving PSCO both the risks of poor

performance and the rewards of good performance. With FSV’s economic problems continuing, PSC retired the plant in 1989.59

I Other Economic Regulatory Incentives

Many States have established direct economic

incentives for plant performance. As of 1989,

about 70 nuclear plants operated under some type

of explicit economic incentive program.60 These

incentives typically use specific formulas to

measure management efficiency and plant performance and relate those to financial rewards or

penalties. Most incentive programs use capacity

factors (CFS)

61 as the primary measure of performance, although other measures are also found,

55 P. Bayne, “Nuclear Power in 1992: A Year-End Review,” remarks to The Energy Daily’s Annual Utility Conference, Dec. 10, 1992.

56 c~o~a pI-JC, Decision 92-08-036, Aug. 11, 1992, p. 3.

5T Pubtic SeNice Compmy of Colortio, Proposed Deco~issioning Plan for the Fort St. Vrain Nuclear Generating Station, NOV. 5, 1990,

pp. 1.1-1 to 1.1-2.

58 Um=overd ~api~ ~os~ ~~l~ded o~~ com~ction cos~ of $2~ ~ion ad later capititi&tions of ~ti~on. OTA SW

conversations with Colorado Public Utility Commission staff, Aug. 25, and Sept. 24, 1992.

w ~ pmlc~ti, due t. FSV’s ~que m- (i.e., tie only commercial gas reactor), the fuel costs were subst~tid. The cost of fuel ~ 1989

would have been approximately 2.8 cents per kw’h. At the same time, PSC could generate coal-fued power for 2.7 cents per kw’b and could

purchase power for only 2.2 cents per kWh. Donald Warembourg, Site Mauager, Fort St. Vrain Nuclear Station+ Public Service Company of

Colorado, personal communication, Sept. 23, 1992.

60 R-L.-p. Hen&ickson ~d J. o~o~ Incentive Regulation of Nuclear power plants by State Public Utility Com”ssions,

NUREG/CR-5509 (Washington+ DC: U.S. Nuclear Regulatory Commission, December 1989). NRC tracks State economic incentive programs

to evaluate their potential impact on safety.

61 Capaciy fXtor is a m=sm of a pl~t’s wtud p~duction of electricity as a percentage of maximum possible production and is defined

as the ratio of the electricity produced to the rated capacity of the facility.
Chapter 3-Economic Lives of Existing Nuclear Plants 85

such as the heat rate (the plant’s thermal efficiency), NRC’s Systematic Assessment of Licensee Performance (SALP) scores, and NRC performance indicators. Incentives for improving

plant operating cost are not limited to nuclear

power plants. For example, incentive based ratemaking has been included in decisions for non-nuclear

activities Columbus Southern Power in Ohio.62

Incentive programs have generally involved

relatively small dollar values relative to total

plant costs. Many of the incentive programs had

awarded no penalties or rewards during the

several-year period reviewed in one NRC report. 63 The largest penalty reported was a 2-year

cumulative $32-million penalty for Public Service Electric and Gas (PSE&G) resulting from an

extended forced outage at the two Peach Bottom

units, of which PSE&G owns 42 percent. 64 I n

comparison, during that 2-year period, PSE&G’s

share of O&M costs for the two plants was far

larger, over $200 million.65

In contrast, PG&E’s Diablo Canyon Units 1

and 2 have a performance-based rate designed to

place the risks and rewards for plant performance

on the utility rather than on the ratepayers.66 The

unconventional rate established by the CPUC in

1988 allows PG&E to receive payments based on

actual plant output rather than on plant construction and operational costs. Since the rate was

established, the plants have performed far more

reliably than had been assumed in the CPUC’s

and PG&E’s analyses. Average CFs, at about 83

percent, have surpassed the assumed 58 percent,

and payments to PG&E between 1989 and 1991

were about $4.1 billion, or about 40-percent

higher than the $2.9 billion originally anticipated. 67 The performance-based rate approach

results in plant economic life decisions being

made more independently by PG&E and less in

conjunction with the CPUC.

The performance-based approach has been

suggested for other nuclear plants but not adopted

to date. For example, as an alternative to SONGS1 early retirement, the DRA proposed establishing a performance-based ratemaking treatment of

future costs.68 Noting that SCE did not pursue the

proposal, the CPUC found that it “would be

novel and complex, might create perverse incentives, and would require much time to work

out. ‘ ’69 Similarly, in 1989 Consumers Power Co.

proposed selling its Palisades plant to a new

entity, the Palisades Generating Co. (PGC), to be

owned by Consumers Power, the Bechtel Power

Corp., and a Westinghouse Electric Corp. subsidiary. 70 Prior to 1989, the Palisades plant performance had been well below the industry average,

with problematic steam generators (SGs) leading

to a lifetime CF of 48 percent. PGC would have

sold its power to Consumers Power under a

long-term purchase contract and accepted the

risks and rewards of plant cost and performance.

However, FERC and the State of Michigan

62 ~~ofio puc t. Consider [ncentive Ratemaking for 06’cM Activities, ” Electric Utility Week, Sept. 21, 1992, pp. 16-17.

63 R L Mart~ p. Hen fic~on and ]. ()]som Incenfi”ve Reg~~afi”on of N~c~ear Pou)er Piant$ by State public Utility CO?n??ti.SSiOnS,

. .

NUREG/CR-5509 (Washington DC: U.S. Nuclear Regulatory Cornmissiom December 1989).

64 us Nu~lefl ReWlatoV Cotission, owners of N~~lear power plants, NuR,EG-0327; Rev. 5. (Wmhingto~ DC: July 1991), p. 6.

65 IJ..S. Dep~ent of Energy, Energy hIfOmMtion~‘ “ tratioq An Analysis of Nuclear Plant Operating Costs: A 1991 Update,

DOE/EIA-0547 (Washington, DC: May 1991), p. 59.

M Callfomla public Utifities (20rnmissioq Decision 88-12-083, at 282.

67 TowNd Utlllv Rate No~izatio~ “petition of Toward Utility ~te No~~ation for Mo&cation of Decision 88-12 -083,’ Sept. 17,

1992, pp. 7-11.

68 c~ifomla Rbhc Utlfities Commission Division of R@3payer AdVOCiMCS, ‘‘Report on the Cost-Effectiveness of Continued Operation of

the SONGS Unit No. l,” Investigation 89-074X)4, Sept. 25, 1991, pp. 45-52.

69 c~fo~a ~blic Utihties Commission Decision 92-08-036, Aug. 11, 1992, p. 23.

70 Feder~ )iner= Re@atoV Commission “~ti~ D~ision on Applications for Approv~ of a power purchase Agreement and tie sale

of Certain Transmission Facilities, ” 59 FERC 63,023, June 17, 1992.
86 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Figure 3-7—Average Nuclear Power

Plant Costs, 1990

Fuel 0.72

r

\

Operation and

r maintenance 1.55 T

(26%)

Capital related (e.g., tax,

depreciation) 3.7

(620/o)

Total 5.97 cents per kWh

SOURCE: U.S. Department of Energy, Energy Information Administration, Electric Plant Cost and Power Production Expenses 1990,

DOWEIA-0455(90) (Washington, DC: June 1992), p. 14.

decided the details of the proposed transfer and

purchase power arrangements were not in the

public interest.71 Among the concerns, the proposed purchase power rates were found to be

excessive, having been based on an assumed

55-percent CF, far lower than the average 74

percent produced in 1991 and 1992 following the

replacement of the plant’s SGs.

ECONOMIC PERFORMANCE OF NUCLEAR

PLANTS

Each nuclear power plant has its own unique

history of cost and performance that differs from

industry averages. Large year-to-year fluctuations in costs are common for most nuclear plants

as capital additions are undertaken and completed. Plant availability also varies from year to

year as the plants undergo refueling and planned

maintenance during 12- to 24-month refueling

cycles. Also, unplanned repair outages contribute

to cost and performance fluctuations.

Economic life decisions are plant specific. In

evaluating the future economic prospects of any

plant, the owners focus on the unique circumstances of that plant-its cost and performance,

and the demand for, and value of, electricity in the

region. While broad industry trends may be

helpful in projecting future cost and performance

of any particular plant, they do not determine the

cost-effectiveness of a plant.

Three types of nuclear power plant costs can

have important and distinct roles in determining

the economic life of individual units:

1. historical capital costs,

2. future capital additions, and

3. annual O&M and fuel costs.

Capital-related costs in the United States on

average are the largest component of total nuclear

power plant costs, about 60 percent higher than

O&M and fuel costs combined (see figure 3-7).72

Together with the plant’s CF, these costs characterize a plant’s economic performance.

# Plant Capacity Factors

Reliability and availability are important factors in nuclear plant life decisions. A plant’s CF

has a large impact on plant economy, since as

more electricity is produced (i.e., as the CF rises)

fried costs are spread over more kilowatt-hours,

reducing the average cost. In the case of SONGS1, Trojan, Rancho Seco, and FSV, CFs well below

the industry average contributed to early retirement decisions. For example, SONGS-1 had a

lifetime CF of about 56 percent, and the 5-year

average prior to the retirement decision was only

44 percent. The lifetime CFs for Trojan and FSV

were about 55 and 15 percent, respectively.

71 ~id.; ad ~c~gm ~bfic Semim Commission, Opinion and Order, Case NOS. U-9507 ad U-9794, June 12, 1992

72 U,S, Dep~entof Energy, Energy ~ormationAchmm“ "stratioWElectricPlantCostandPowerProductionExpe~es 1990, EIA-0455(90)

(Washington DC: June 1992), p. 14.
Chapter 3--Economic Lives of Existing Nuclear Plants 187

Future CFs at any plant are uncertain and thus

subject to disagreement in economic analyses.

For example, based on its analyses of other plants

and effects of planned and completed maintenance activities, SCE suggested that reasonable

CF scenarios for SONGS-1 ranged from 60 to 80

percent. In contrast, the DRA considered a range

of 44 to 70 percent more likely based on its

assessment of other plants and prospects.73 Similarly PGE considered CFs ranging from O percent

to over 80 percent in its analyses of Trojan, with

an expected value of about 60 to 64 percent,

depending on the replacement of SGs.

Average CFs at U.S. nuclear facilities have

increased substantially in the past few years from

an historical average of under 60 percent to over

70 percent in 1991 (see figure 3-8).74 INPO has set

an industry-wide median CF goal of 80 percent by

1995, which it views as a challenging but

achievable target.75 Nuclear plants do not operate

continuously for several reasons:

to allow for refueling outages, which typically

require several weeks at least once every 2

years;

for planned plant maintenance and capital

additions (discussed below), which are performed concurrently with refueling to the extent

possible, but often involve additional time;

for equipment failures causing unscheduled

maintenance; and

for other operational problems (e.g., if plant

operators fail to pass annual NRC qualification

tests).

Figure 3-8-Average U.S. Nuclear Power Plant

Capacity Factors, 1973-1991

‘“~- ‘------- ‘

- “-- 1I

70 1

● +./ “

60- /

J ‘]

(

50-

20+ I

01 1 1 1 ) I 1 I 1 I I 1 I I I ,, I 1973 1976 1979 1982 1985 1988 1991

SOURCE: U. S. Department of Energy, Energy Information Administration, Annual Energy Review 1991 DOWEIA-0384(91) (Washington,

DC: June 1992), p. 237.

The need to refuel and conduct maintenance

every 1 to 2 years creates a practical limit to

overall CFs of about 80 to 90 percent over a cycle.

One EIA analysis identified three factors that

contributed to the lower CFs of the 1980s,

including increased safety and regulatory requirements, degradation of major equipment, and

management problems.

76 Many of the safetyrelated outages resulted from NRC’s Three Mile

Island (TMI) action plan,77 involving shutdowns

for plant modifications and safety audits. EIA

noted one series of EPRI reports that estimated

that NRC regulatory actions accounted for about

73 c~lfomla public utilities Cornmissio% Division of Ratepayer AdVOCateS, ‘‘Report on the Cost-Effectiveness of Continued Operation of

the SONGS Unit No. l,” Investigation 89-07-004, Sept. 25, 1991, pp. 6-10.

74 U.S. Dcp~ent of EnerH, EnerH ~omtion Adminis@atio~ Annual Energy Review 199], DOE/EIA-03gLl(91) (Washington, ~:

June 1992), p. 237.

75 ~Stitute of Nuclem power OPeratlom, 1992 pe~ormance ]ndicatorf for the us, Nuclear utili~ Industry (Ati~t~ GA: M~h 1993).

76 W. I-.iggett and K.C. Wade, ‘‘Improvements in Nuclear Power Plant Capacity Factors, ’ Electric Power Monthly, DOE/EIA-0226(93/02)

(Washington DC: U.S. Department of Energy, Energy Information Administration February 1993).

77 us, Nuclea Rewla[ov commi~~ion, clarl~cation of the TM[Ac{i~n plan Requi~ents, WG-0737, November 1980.
88 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Virginia Power completed its steam generator

replacement project at the North Anna plant well

under budget, with lower occupational exposures, and

in less time than had been anticipated.

10 percent reduction in CFs between 1980 and

1988. 78 Aging degradation of some major plant

components such as recirculation pipes in boiling

water reactors (BWRs) and SGs in pressurized

water reactors (PWRs) have required a variety of

maintenance activities including major equipment replacements that also reduced CFs. For

example, steam generator replacement outages

have generally required several months, although

one recent experience at Virginia Power’s North

Anna plant has reduced that time greatly.79 In

addition, improved water chemistry and better

materials used for major component replacements

have reduced equipment degradation rates and the

resulting outage times.

Finally, EIA noted that management problems

in some plants led to poor CFs in the 1980s, a

problem mitigated by INPO and EPRI industrywide efforts to promote the best practices in use.

Still, while industry averages have clearly improved, a wide diversity in the range of plant CFs

remains (see figure 3-9). For the 96 plants

operating during the 3-year period 1989-1991, 80

27 plants had a CF above 80 percent, while 13 had

below 50 percent, with an average of 67 percent.81

In comparison, one-third of the 61 plants between

1980 and 1982 had CFs below 50 percent, and 13

percent had CFs above 80 percent. Internationally, several countries with large numbers of

nuclear plants have had higher average CFs than

U.S. plants, while others have had lower CFs. For

example, for the year ending June 1992, the

average annual CF for Japan’s 42 plants was 73

percent compared to 69 percent for the United

States, and 63 percent for France’s 55 units. 82

1 Historical Capital Costs

Over half of the total generation expenses for

U.S. nuclear plants is related to recovery of

historical capital costs. 83 These historical capital

costs include the initial construction costs and

later capital additions (i.e., major nonrecurring

repairs or retrofits performed to improve plant

performance or meet safety requirements). As of

1990, the capital invested in operating nuclear

78 Elec~c poWm Resewch ~stitute, Nuclear Unit Operating Experiment: 1980 through 1988, 1991.

79 “Virginia Power’s North Anna-1 Unit Returned to Service in Record Time,” Elecm”c Utility Week, Apr. 19, 1993, pp. 6-7.

so Becau~ ye~to year fluctuations are routine, aphmt’s COSt md prfo~ ce in any given year may differ greatly from its long-term record.

For this reason, meaningful comparisons between the performance of different plants should consider multiple years.

61 W. Liggett and K.C, Wade, {

‘Improvements in Nuclear Power Plant Capacity Factors,’ Electric Power Monthly (Washington DC: U.S.

Department of Energy, Energy Information Administration, February 1993).

62 Nucle~ ~gin=ring International, World Nuclear Industry Handbook 1993, p. 18.

83 U.S. Dep~ent of Energy, lher~ Mormation Administratio~ Electric Plant Cost and Power Production Expenses 1990,

EIA-0455(90), June 1992, p. 14.
Chapter 3-Economic Lives of Existing Nuclear Plants 189

power plants totaled over $150 billion.84 Utility

investments in these historical capital costs are

gradually recovered in utility rates over the life of

the plant through depreciation and return on

investment.

As utility costs increased in the 1980s, many

State regulatory commissions scrutinized utility

expenditures more closely, especially the often

large construction cost escalations for nuclear

plants. In some cases, regulators found that plants

were unnecessarily expensive or that the generating capacity was not needed and did not allow the

utility to recover the full costs from customers.

These disallowances may have been justified, but

may make utilities reluctant or unable to continue

investing in existing plants, especially if high

capital costs are involved. For example, a 1992

decision of the Illinois Commerce Commission

(ICC) raised the prospect that much of CECO

$7.1 billion investment in the Byron 2 and

Braidwood-1 and -2 plants were not “used and

useful, and thus may not be recovered. As a

result, CECO announced substantial cutbacks in

capital investment and operating costs and was

considering closing nuclear or fossil plants.85

Increasing competitive pressures in the electric

power industry can also affect a utility’s ability to

recover capital costs. For example, Public Service

of New Mexico (PNM) took a $127 million

write-down for its 130-MW (10 percent) share of

the Palo Verde unit 3 nuclear power plant in

1992. 86 According to PNM’s chairman, the writedown was a move towards “positioning the

company for the inevitable open and competitive

electric marketplace. ’

Figure 3-9-Range of Capacity Factors Over 3-Year

Interval, 1989-1991

45 “r—–- ‘-

22

— — —

<5070 50-650/o 65-800/o Moo/o

Capacity factor

SOURCE: W. Liggett and K.C. Wade, “Improvements in Nuclear Power

Plant Capacity Factors,” E/*tfiPowerMonfh/y (Washington, DC: U.S.

Department of Energy, Energy Information Administration, February

1 993).

1 New Capital Additions

Capital additions are the plant upgrades that

include repairs or replacement of major equipment (e.g., replacing SGs) and major plant

modifications. Capital additions are generally

distinguished from other maintenance costs in

that they involve large expenditures on equipment expected to last many years. Capital additions may be needed to meet NRC safety requirements (e.g., seismic and fire control backfits), or

utilities may perform them to maintain or improve

plant economy, safety, or both. One study of four

nuclear plants found that the portion of capital

84 NofimI doll~s in year ~vesled. U.S. Department of Energy, Energy Information Adrninistratiou Financial Stafi”sfi”cs ofseiectedhve$tor

Owned E/ecm”c Utilities 1990, DOE/EL4-0437(90)/l, January 1992, p. 40; U.S. Energy Information Administration, Financial Statistics of

Selected Publicly Owned Electric Utilities 1990, DOE/EIA-0437(90)L2, February 1992, p. 15; and U.S. Department of Agriculture, Rural

Electrification Adrninistratiom 1988 Statistical Report, Rural Electiic %rron’ers, REA Bulkti Number 1-1, 1989.

85 fccomo~w~]~ ~owces ~tb~C~, K~ps P]ant C]ostigs Option Ope@” Nucleonics week, VO1. 33, No. 31, July so, 1992, pp. 1-2.

86 CLPNM sew $lA2.s-Million Write-Down Tied to Excess Generating Capacity, ” Electric Utility Week, Feb. 8, 1993, pp. 9-10.
90 I Aging Nuclear Power Plants: Managing PIant Life and Decommissioning

Figure 3-10—Average Annual Nuclear Power Plant Capital Additions Costs 1974-1989

(1991 dollars per kilowatt of capacity)

70 T —

I

60-

~ 50-

~

$ 40-

1

: s. 1

.FJ

~ 20-

4

l o -

0 1 1 1 r 1 1 1 I 1 1 [ 1 I I

1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989

SOURCE: Office of Technology Assessment, adapted from U.S. DOE, Energy Information Administration, An Ana/ysis

of Nuclear Power P/ant Qerating Costs.’ A 1991 Update, DOEHA-0547 (Washington, DC: May 1991).

additions costs attributable to NRC safety regulations varied between 34 percent and 65 percent.87

The large, one-time costs involved and the

potential for long outages may make capital

addition decisions de facto plant life decision

points. For example, the economic analysis leading to the SONGS-1 early retirement decision was

initiated because of the large capital additions

request filed by the plant’s owner.88 Similarly, the

need to replace the SGs at a cost of up to $200

million weighed heavily in PGE’s decision to

retire the Trojan nuclear plant, along with the

availability of lower cost electricity options.89

Historical average capital additions costs have

varied greatly, hitting a peak in the mid-1980s

(see figure 3-10).90 Some capital additions have

been required to mitigate aging degradation, for

example, replacements of recirculation system

piping in BWRs and SGs in PWRs. Other capital

additions have been unrelated to aging, but

resulted instead from deficiencies identified in

plant design, such as the TMI and Browns Ferry

fire protection backfits.91 The variety and number

of capital additions has been great. For example,

table 3-1 shows the variety of major capital

additions reported as construction work in progress in 1988. Although any particular capital

addition is nonrecurringg, most plants have experienced a series of different capital additions.

Because capital additions typically involve

long-lived equipment changes, the costs are not

recovered entirely in utility rates in the year they

are expended but rather are recovered gradually

over several years, as are construction costs. As a

result, the expected remaining operating life of a

plant can be an important factor in determining

87 ~C&A, ~c., “Analysis of the Role of Regulation in the Escalation of Capital Additions Costs for Nuclear Power Plants,”

ORNL/Sub/88-SC557/l (Oak Ridge, TN: Oak Ridge National Laboratory, July 1989).

88 Cwornia Public Utilities Commission Order 1.89-07-004

69 port~d Gener~ Electric Co., 1992 lntegrured Resource P/an, NOV. 13, 1992.

w capital additions COStS are not explicitly reported to the Federal Government as plant-specific costs by utilities iKI their ~ud “FERC

Form 1“ filings, making it difficult to estimate them accurately. U.S. Department of Energy, Energy Information Administration+ An Ana/ysis

of Nuclear Plant Operating Costs: A 1991 Uphte, DOE/EIA-0547 (Washington DC: May 1991).

91 10 CFR 50, app. R.
Chapter 3--Economic Lives of Existing Nuclear Plants 191

Table 3-l—Capital Additions in Progress in 1988

Total construction

work in progress

Number of expenditures

Category utilities ($millions)

Steam generators. . . . . . . .

Low-level waste. . . . . . . . .

Fire protection. . . . . . . . . .

Turbine, generators. . . . . .

Water chemistry. . . . . . . . .

Control room. . . . . . . . . . . .

Core cooling. . . . . . . . . . . .

Simulators. . . . . . . . . . . . . .

Spent fuel storage. . . . . . .

Piping, tubing. ... , . . . ., .

Emergency systems. . . . . .

Reg Guide 1.97. . . . . . . . .

Control rod drive. . . . . . . . .

20 other categories. . . . . .

9

13

14

13

18

16

14

19

14

13

13

4

8

109

92

90

79

51

43

39

38

36

35

26

26

21

197

SOURCE: American Nuclear Society, Supplement to the “Dollar Facts

About the U.S. Operating Nuclear Power Planf Markef”, Study No. 9,

Section 1, 1990.

the economic attractiveness of a capital addition.

For plants requiring major capital additions but

approaching the end of their operating license,

resolution of license renewal requirements can

therefore play an important role in capital planning.

1 Fuel, Operation, and Maintenance Costs

Average real fuel and O&M costs per unit of

output for nuclear power plants increased markedly between 1974 and 1987 but have since

declined by about 20 percent (see figure 3-11).92

Overall, real O&M and fuel costs per unit of

production in 1991 were about 2.2 cents/kWh,

more than double what they were at their low in

1971. There is general agreement that a return to

rapid O&M cost escalation could make existing

Figure 3-11—Nuclear Power Plant Production

costs 1970-1991 ($1991)

30 ~ —7

0

1 D Fuel

‘4

_ Non-fuel

I

4

1970 1974 1978 1982 1986 1990

SOURCE: Nuclear Engineering International, September 1992, p. 45;

nominal dollars adjusted using Consumer Price Index.

nuclear plants economically unattractive. 93 Diversity in O&M costs among existing plants is

great. For example, the 3-year (1990 to 1992)

average O&M cost for the 10 most economic

plants was 55 percent below the average industry

cost (see figure 3-12).94

Much of the historical rise in production costs

is attributable to increased plant staffing. Staffrelated costs have been estimated at approximately two-thirds of total reported O&M costs.95

Between 1977 and 1990, staff levels at single unit

nuclear plants increased from an average of about

150 employees to over 1,000.96 Several factors

help explain plant staff increases. Part of the

increase in average plant staffing resulted from

the completion of larger plants. However, staff

size at the same plants has increased substantially

92 NucIear Engineering International, September 1992, p. 45; nominal dollars tijusted using Consumer price ~dex.

93 See, e,g., NuClem Management ~d Resources COUCfl, “Review of Operations and Maintenance Costs in the Nuclear Industry,”

NUMARC 92-03 (Washington DC: December 1992), pp. 2, 54; and J. G. HewletJ “The Operating Costs and Ixmgevity of Nuclear Power

Plants,” Energy Policy, July 1992, pp. 608-622.

94 *fWo~Cr@k ~ad~ As US. uti~tie~ Hone Nuc]~ ~onofic perfo~ cc, ” Nuc!eonics Week, vol. 34, No. 25, June 24, 1993, pp. 7-10.

95 HI. Bowa5, L.C. Fu~~, ~d M.L.Myers, Cost Esti~ring Relationships for Nuclear power plant Operation and Maintenance,

ORIWJI’M-10563 (Oak Ridge, TN: Oak Ridge National Laboratory, November 1987).

96 ‘tHow -ypeople Does It T&e To R~ a Nucl~ powerpl~t?” E/ectn.ca/ World, July 1992, pp. 9-1s.
92 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Figure 3-12—Diversity in Nuclear Plant Fuel

and Operating and Maintenance Costs

(3-year average cost, 1990-1992)

6 ,

2.65

r

Average

of ail

1.43 I Ink

5.3

I

10 highest

cost

units

SOURCE: “Wolf Creek Leads As U.S. Utilitiea Hone Nuclear Economic

Performance,” Nocleonics Week vol. 34, no. 25, June 24, 1993, pp.

7-1o.

over time. For example, the staffing level at the

Ginna nuclear plant grew from 59 people in 1970

to approximately 600 in 1990.97 Other factors

include increasing safety and NRC regulatory

requirements, economic incentives, and regional

conditions, although much of the variation remains unexplained. In contrast to O&M, fuel

costs have remained relatively stable in real terms

over the past two decades.

Federal reporting requirements do not specifically address several important overhead costs,

potentially leading to inaccurate assessments of

nuclear plant costs. Overhead costs include annual NRC operating license fees of about $3

million per plant,98 nuclear liability insurance,

plant staff benefits, and other factors, many of

which are uniquely or predominantly associated

with nuclear plants.99 These costs are typically

reported by utilities in their annual ‘‘FERC Form

1“ filings as company-wide costs rather than

plant-specific costs and can be difficult to estimate accurately. In total, overhead costs represent

a substantial portion of total operating costs,

estimated in one analysis at about 30 percent of

the reported O&M costs. 100 Although many

published reports do not include these costs,101

they are important to consider in economic

decisions about plant life.

FACTORS AFFECTING FUTURE COST AND

PERFORMANCE

Several factors affecting nuclear plant cost and

performance will likely play important roles in

the future. These include:

plant aging;

competitive pressures;

nuclear industry evolution, including new experience, technology, and NRC regulatory

changes; and

radioactive waste disposal.

In an analysis of nuclear production costs, EIA

attempted to examine the key factors but found no

analytical measure to differentiate the effects of

NRC regulatory requirements from the effects of

97 Nuc]e~M~agemen~~d Resources coulIcil, “Review of Operations and Maintenance Costs in the Nuclear Industry,’ NUMARC 92-03

(Washington DC: December 1992), p. 19.

9810 cm 171.15+

99 H.I. BOWWS, L.C. Fuller, ~d M.L.Myers, Cost Estiman”ng Relationships for Nuclear Power Plant Operation and MainteMnce,

ORNIJI?M-10563 (Oak Ridge, TN: Oak Ridge Nationat Laboratory, November 1987).

‘m Ibid.

101 See for example, U.S. DOE, Energy rQfO-tiOn~‘ ‘stratio% Electn”c Plant Cost and Power Production Expenses 1990,

DOE/EIA-0455(90), June 1992, table 14, “Average Production Expenses for Nuclear Steam-Electric Plants Owned by Major Investor-Owned

Electric Utilities, 1985-1990;” U.S. DOE, Energy Information A&mm“ “stratio%An Analysis ofNuclear Plant Operating Costs:A 1991 Upalzte,

DOE/EL4-0547, May 1991, p. 5.; and Jim Clarke, “Nuclear O&M Costs Sliding Downward, UDI Says,” The Energy Daily, vol. 20, No. 127,

hdy 2, 1992, p. 1.
Chapter 3-Economic Lives of Existing Nuclear Plants 193

new technology and information.102 Further, the

analysis lacked information to distinguish between safety-related activities that a utility would

have and have not undertaken on its own absent

NRC requirements. Similarly, no method was

found to distinguish between plant aging (which

should increase costs) and utility experience

(which could either increase or decrease costs).

Some general attributes of the factors affecting

cost and performance are noted below.

1 Effects of Age on Cost and Performance

Plant maintenance to address aging degradation involves a variety of monitoring, evaluation,

repair, and replacement activities. Some of these

activities involve major capital additions, which

may be very costly and could prove to be plant life

decision points. Utilities are increasingly developing life-cycle management approaches to coordinate long-term capital planning and mitigate

aging degradation for major systems, structures,

and components (SSCs).103 Although expensive,

some aging management activities may actually

lead to improved economic performance. For

example, addressing aging involves improving

maintenance programs generally, allowing for

preventive or reliability centered maintenance

rather than corrective maintenance. The result of

applying a preventive maintenance program can

be both lower costs and improved availability.104

Plant experience may improve performance with

age as well. This factor, however, is difficult to

distinguish from other age-related effects on

operational and capital additions costs.

Given the lack of experience with large nuclear

plants beyond the middle of their 40 year licensed

lives, available evidence to predict accurately the

long term effects of aging on economic performance is limited but continues to evolve.105 As of

1992, only 21 plants were 20 years or older. Those

plants are smaller than the younger units, with an

average capacity of 616 MW compared to 974

MW.106 The evolving experience and research is

particularly important for those relatively few,

but often major, SSCs intended to last the life of

a plant (e.g., the reactor pressure vessel, the

containment structure).

EIA’s analysis of operational costs for existing

plants (which, for the study period, had attained

an average age of only 13 years) suggests that

over the frost third of a plant’s assumed design

life, the beneficial effects of increasing experience outweighed aging degradation effects, and

costs decline with increasing age.107 However,

capital additions costs appeared to increase with

age for BWR plants.

The costs of addressing aging degradation have

played a role in each of the three early retirement

decisions announced in 1992. For the SONGS-1

and Trojan plants, steam generator deterioration

were primary aging issues, while the costs to

resolve a pressure vessel embrittlement issue

contributed to Yankee Rowe’s closure.

la u.S. Depfient of Energy, fier~ ~ormation~“ “stratio~ An Analysis of Nuclear Plant Operating Costs: A 1991 Update,

DOE/EIA-0547 (Washington, DC: May 1991).

103 see, e.g., Grove En@&ring, IIIC., ~ng.Te~ Capita[planning Considering Nuclear Plant L~e-Cycle Ma~~ernent, Ep~ T’R-101 162

(Palo Alto, CA: Electric Power Research Institute, September 1992); and Stone and Webster Engineering Corp. and Baltimore Gas and Electric

Co., Service (Saft) Water System Life-Cycle Management Evaluation, EPRI TR-102204 (Palo Alto, CA: Electric Power Research Institute,

April 1993).

104 Nofiem stite~ poww Co~p~y,BWR PllotPluntLl~e~re~lon Sfw attheMontice~[o Pl~nt:Inren”rnPhase 2, EPRl NP-5836M (Pdo

Alto, CA: Electric Power Research Institute, October 1988).

105 J.G. Hewle~, ‘‘ne operating Costs and Longevity of Nuclear power PLuIts,’ Energy Policy, July 1992, pp. 608-622.

106 us. D~p~ent of EnmU,Nuc~earReactor5 Built, BeingB~”ft) or planned: 1991, ~E/OS~.82~R55 ~~ti~o~ ~: July 1W2),

pp. ix-xiv.

107 T-J,s. Dep~ent of Energy, Ener~ ~Ormation ~‘ “stratio% An Analysis of Nuclear Plant Operating Costs: A 1991 Update,

DOE/EIA-0547 (Washington, DC: May 1991), p. 9.
94 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

I Competitive and Regulatory Pressures for

Improved Cost and Performance

The past years’ early retirements and increased

attention to the prospect of retirements at other

plants have heightened the awareness that poor

plant economic performance may have serious

consequences. Increasing State regulatory attention to plant life issues as part of IRP efforts and

intensifying competition in the electric power

market may be powerful motivators for improving nuclear plant costs and performance. One

indication of growing industry attention is the

development of the Industrywide Initiative noted

earlier to improve plant economic performance.

The resulting rate of adoption of new cost- and

performance-improving measures, and the overall effect on nuclear plant competitiveness, remains to be seen.

Recent efforts by several utilities to reduce

nuclear plant staffing, a primary component of

plant O&M, provide an example of a growing

effort to control costs.108 Since 1992, several

utilities have announced efforts to reduce nuclearrelated personnel. For example, Philadelphia

Electric Co., operator of four nuclear plants

(Peach Bottom units 2 and 3 and Limerick units

1 and 2) announced plans to reduce 635 of 3,400

nuclear operations positions by 1995 for an

expected savings of about $35 million to $38

million annually.109 Similarly, Niagara Mohawk

has announced its consideration of cost cutting

moves to reduce its 2,000-person nuclear division

staff by 20 percent as part of an effort to reduce

O&M costs in order to keep operating.110 The

Washington Public Power Supply System also

announced plans to reduce its nuclear plant work

force of 1,400 by 300.111

The industry continues to develop new technologies with the prospect of improving nuclear

plant economic performance. Among them are a

variety of maintenance approaches including

advanced decontamination techniques, reducing

worker exposures and thus labor costs (see box

3-A); remote surveillance and robotics that allow

monitoring and repair of equipment in previously

inaccessible or expensive to work in areas;

predictive maintenance practices that allow for

better planning of maintenance activities (see ch.

2).

The experience of Virginia Power in replacing

the SGs at its North Anna-1 plant is one example

of how increased experience may aid in controlling costs. That effort took a far shorter time than

planned and typically found in previous SG

replacement projects (51 days rather than the

planned 150 days); cost substantially less ($130

million rather than the $185 million planned); and

resulted in far lower occupational exposures (240

person-rem rather than the 480 predicted).112

Virginia Power noted that the much better than

expected effort resulted from previous experience

with Surry 1 and 2, careful advance planning,

attention to detail, and support from the project

engineer, Bechtel Corp. Not all major projects

may be so fortunate, however. For example,

steam generator replacement for Millstone unit 2,

completed in January 1993 and projected to cost

$190 million, took 228 days, 93 more than

planned.

10s Utility cost control efforts are not resrncted to nuclear plants. Many utilities are reducing non-nuclear Staffii, as well, m pm of tie~

efforts to meet growing electric industry competition. See, e.g., “Redeployment to Cut PSE&G Jobs by 500-4% of Total-by Early ‘94,”

Electric Utility Week, Apr. 19, 1993, p. 3; and “PG&E to Freeze Rates Through 1994, Cut Industrial Rates $lOf)-MilliorL” Electn”c Utility

Week, Apr. 19, 1993, p. 17.

lw Electric utili~ Week, NOV. 30, 1992, p. 6; and Nucleonics Week, Apr. 22, 1993, p. 4-5.

110 ‘{N&fo~s Cost.titfig Res~ts in 1,400 Lost Jobs,” Elecm”c Utility Week, Feb. 8, 1993.

1 I 1 Harriet King, “Northwest Nuclear Plant’s New Strategy,” New York Times, June 9, 1993, p. D-3.

112 “V~@a powti sets World R~Ord for Steam Generator Replacement” Nucleonics Week, Apr. 15, 1993, pp. 1,11-12.
Chapter 3-Economic Lives of Existing Nuclear Plants! 95

Box 3-A—Chemical Decontamination

In performing analyses to determine cost-effective occupational radiation exposure reductions, the industry

typically uses a value of $10,000 per man-rem.1 Chemical decontamination techniques represent an increasingly

common method to reduce occupational radiation exposures and, thereby, operational costs at existing

commercial nuclear power plants.2 Decontamination-such as manual scrubbing or washing with chemical

agents-removes radiologically contaminated materials created in the pressure vessel that have dispersed and

settled throughout a steam supply system by the circulation of cooling water.

Experience with chemical decontamination at operating reactors has increased substantially in the last

decade, particularly with the development of softer (i.e., less extreme pH ranges), more dilute solutions that cause

less wear (e.g., corrosion, pitting, intergranular attack) on plant materials and systems.3 Early experience with

concentrated chemical decontaminants produced high levels of decontamination. However, because of the

attendant problems of corrosion damage and waste disposal, concentrated processes will probably not be applied

to operating reactors again. A variety of dilute chemical decontaminants can achieve comparable decontamination, but application times vary, which is a more important consideration for operating reactors than retired ones,

because of the relatively higher costs for extended down times.

Most applications have been on boiling water reactors (BWRs), particularly as part of pipe maintenance

efforts. For BWR applications, 66 to 75 percent of the contaminant radioactivity and corrosion products have been

removed in the first chelating step.4 Although greater levels of decontamination are possible with multiple

washings, waste volumes increase with each washing step and, with some recirculating processes, the potential

for recontamination increases.

Opportunities exist to make chemical decontamination potentially more effective. Although at least 60

commercial nuclear plant systems at more than 20 reactors have been chemically decontaminated using dilute

solutions, no plant has attempted decontamination of the entire reactor coolant system. Consolidated Edison (Con

Ed) has proposed demonstrating a full system decontamination (FSD) at its Indian Point unit 2 plant.5 Con Ed

estimates that FSD can reduce radiation fields by a factor of at least five, saving 3,500 man-rems (with an estimated

value of $35 million) over the nearly 20 years remaining in the life of the plant.6

I Consolidated Edison, “Abstract: National Demonstration of Full RCS Chemical Deoontamination,” 1992.

2 J.F. Remark, Applied Radiological Control, Inc,, A BevjewofP/atiW@nfam/natjon Methods: 7988 U@8fe,

EPRI NP-6169 (Palo Alto, CA: Electric Power Research institute, January 1989), p. 2-9.

3 C.J, Wood and C.N. !3paiaris, Soumebook for Chernka/ Decontamination of WclearPowerPlants, EPRI

NP-6433 (Palo Alto, CA: Electric Power Research Institute, August 1989), pp. 1-1,1-4,2-1.

A J.F. Remark, Applied Radiological Control, Inc., A ~evjewOfP/atiDe~~ta~i~afiO~ hfethod: 1988 L!@afe,

EPRI NP-6169 (Palo Alto, CA: Electric Power Research Institute, January 1989), pp. 2-1 to2-3, 2-8 to2-9; C.J. Wbod

and C.N. Spalaris, Source600k for Chemical Decontamination ot/Vuclear Power P/ar?ts, EPRI NP-6433 (Palo Alto,

CA: Electric Power Research Institute, August 1989), p. 2-8.

5 J.B. MaSon et al., FLI// Reactor Coo/ant syStem Chemical Decontamination at Consolidated Edjson /ndian

Pojnt-2 Plant, Pacific Nuclear Services, November 1991.

6 Consolidated Edison, “Abstract: National Demonstration of Full RCS Chemical Decontamination,” 1992.
96 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

9 Evolving NRC Activities

Since its creation in 1974, the NRC has often

revised regulatory requirements with the goal of

assuring adequate safety. These requirements can

result in increased operational and capital additions costs. However, to the extent that NRC

requirements reflect new experience and information, at least some of these efforts could have been

undertaken as part of industry safety efforts even

absent NRC’s mandates. In response to an NRC

request, 113 NUMARC has identi.tied several regulatory requirements that it believes result in

increased costs without commensurate benefits to

safety. One aspect of the Industrywide Initiative

developed by the nuclear industry is to reduce

overall costs while maintaining current safety

levels as well as to focus on how to change the

responses of nuclear utilities to regulatory activities. 114

Assessing the extent to which future safety

regulatory changes, including those related to

managing aging, will affect costs at existing

nuclear plants is necessarily speculative. As

discussed in chapter 2, major aging-related regulatory activities currently include: final implementation of the maintenance and license renewal

rules; elevation of fatigue and environmental

qualification of electrical equipment to generic

safety issues; and resolving how to demonstrate

compliance with reactor pressure vessel embrittlement.

1 Radioactive Waste Disposal

Disposal of spent fuel and low-level waste

(LLW) may present increasing future costs. In

One of Virginia Power’s dry storage casks for spent

fuel.

1991, spent fuel discharges from commercial

nuclear power reactors totaled 1,915 metric tons.

The total inventory of discharged commercial

spent fuel (collected from 1968 to 1991) in the

United States is 23,731 metric tons.115 The total

inventory is projected to increase to about 32,000

metric tons in 1995 and 42,000 metric tons by

2000.116 Water-filled pools in the reactor building

are used to cool and store spent fuel for at least 5

years. Under the Nuclear Waste Policy Act of

1982117 (NWPA), the Federal Government is

ultimately responsible for disposal of spent fuel,

although progress to date has been limited (see

box 3-B).

Inadequate spent fuel storage capacity, together with the lack of progress in DOE’s

programs, place both direct and indirect costs on

existing nuclear power plants. According to data

compiled from recent DOE surveys, 28 operating

reactors, about 25 percent of all 107 U.S. plants,

will have inadequate spent fuel storage capacity

1]3 “Virginia Power Sets World Record for Steam Generator Replacement” Nucleonics Week, Apr. 15, 1993, pp. 1, 11-12.

114 NuclwMmgementmd Reso~es co~cfl, 1‘Reviewof Operationsmd wte~cecosts ktheNucleuhdus~,” NUMARC 92-03,

December 1992, p. 55.

115 U.S. Dep~ent of Energy, fiergy ~orrnation Administratio~ Spent Nuclear Fuel Discharges From U.S. Reactors 1991,

SR/CNEAF/93-01 (W%shingtom DC: February 1993), p. 21. Note: Tonnage figures reflect weight prior to irradiation a proxy measure of the

f~ spent fuel weight,

116 u.S. Deptient of Energy, Energy hformation ~“ “stratioq World Nuclear Capacity and Fuel Cycle Requirements 1992,

DOE/EIA-tM36(92) (Washingto4 DC: November 1992), pp. 13-14.

117 Nucl~ Waste policy Act of 1982, Pllblic bW 97425, Jm. 7, 1983.
Chapter 3--Economic Lives of Existing Nuclear Plants 197

Box 3-B–Federal Nuclear Waste Disposal Efforts

The Nuclear Waste Policy Act of 19821 (NWPA) established the Office of Civilian Radioactive Waste

Management within the U.S. Department of Energy (DOE) and directed the Secretary of Energy to open a

repository for spent fuel by January 1998. To pay for this work, NWPA established the Nuclear Waste Fund and

set a fee of 0.1 cents per kilowatthour of electricity generated by commercial nuclear plants. As of September 1991,

the Fund had collected nearly $8 billion in fees and $2 billion in interest, about $3 billion of which had been

spent. 2 However, the original 1998 target date for opening the repository will not be met. Under current

plans, DOE expects to complete site characterization work at Yucca Mountain, the only location being investigated,

by 2002.3 DOE estimates that a geologic repository will be ready no sooner than 2010. In a report to Congress

and the Secretary of Energy, however, the Nuclear Waste Technical Review Board concluded that even the 2010

schedule appears unrealistic.4

As an interim measure, DOE has claimed it would open a monitored retrievable storage (MRS) facility to

accept spent fuel by 1998. As with a geologic repository, there are serious doubts about whether this will be

available on schedule. In particular, the queue for the first 10 years of spent fuel transfers to an MRS has already

been established through a DOE application process. The licensees that will deliver spent fuel, including the

quantities and years of disposal, have already been selected.

Undercurrent plans, DOE expects to accept 8,200 metric tons of spent fuel from 60 licensees (including itself)

in the first 10 years after an MRS opens.5 That represents less than 40 percent of the current commercial spent

fuel inventory and only about 15 percent of the expected inventory by 2008, the soonest the transfers could be

completed under the current schedule, assuming a 1998 start date.6 Even with a 1998 start date, however, most

of the vulnerable 28 units will have to have made other plans or face closure.

In 1992, DOE suggested building the MRS on Federal sites7 together with development of integrated casks

for shipping, storage, and disposal, but the ultimate public, congressional, State, and utility response to the

proposal are not yet known. In fact, the recent legal challenges by the State of Idaho to halt shipments of spent

fuel from the Fort St. Vrain reactor in Colorado to the Idaho National Engineering Laboratory (INEL) suggest that

there can be serious resistance to the use of existing Federal sites for waste storage or disposal.

1 Nuciear Waste Policy Act of 1982, Public bw 97-425.

z U.S. I)epartmentof Energy, Office of Civiiian Radioactive Waste Management, Annual t?eportto @n9~esS.’

Office of Civilian Radioactive I&We Management, DOE/RW-0335P (Washington, DC: March 1992), pp. 54,65. In

simple terms, a 1,000 MWe reactor operating at 80 percent capacity in a given year wouid be subject to roughly $7

miilion in Nuclear Waste Fund fees.

3 U.S. Department of Energy, Office of Civilian Radioactive Waste Managemmt, Pfogfess ~ePOrt on the

Scientific Investigation Program for the Nevada Yucca Mountaih Site, No. 6, DOWRW-0307P-6 (Washington, DC:

September 1992), p. 1-2.

4 Nuclear Waste Technical Review Board, /VWT/?B Special Report, (Adk@On, VA: Mar* Igw), P. v.

5 U.S. Department of Energy, Office of Civilian Radioactive Waste Management, Annual capacity Rep@

DOE/RW-0331 P (Washington, DC: December 1991), pp. v-vi, 9. A metric ton equals 2,204.6 pounds. Nuclear fuei

weights are generaiiy given in metric tons of initial heavy metal (MTIHM), which refers to the original mass of the

actinide fuel elements (rnostiy uranium).

6 U.S. DOE prc@ticms of the total inventory of commercial spent fuei by 2008, assuming no ww reactors

are ordered, is 56,500 metric tons. U.S. Department of Energy, Energy Information Administration, WxldNuc/ear

Capacity and Fuel Cycle Requkements 1992, DO13EIA-0436(92) (Washington, DC: November 1992), pp. 13-14.

7 J-SD. Watkins, Secretary, U.S. Department of Energy, letter to J. Bennett Johnston, Chdrman, Senate

Committee on Energy and Natural Resources, Dec. 17, 1992, attachment, pp. 1-2.
98 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Table 3-2—Plants Projected to Require Additional

Spent Fuel Storage Capacity by the Year 2000

Design Loss of

capability operability

Facility (State) (MW) (Year)

Palisades (Ml). . . . . . . . . . .

Prairie Island 1 (MN), . . . .

Prairie island 2 (MN). . . . .

Calvert Cliffs 2 (MD). . . . . .

Limerick 2 (PA). ... , . . . . .

Nine Mile Point 1 (NY). . . .

Point Beach 1 (WI). . . . . . .

Point Beach 2 (WI). . . . . . .

Calvert Cliffs 1 (MD). . . . . .

Peach Bottom 2 (PA). . . . .

Waterford 3 (LA). . . . . . . . .

Arkansas Nuclear 1 (AR). .

Big Rock Point (Ml). . . . . .

Dresden 2 (IL). . . . . . . . . . .

Duane Arnold (1A). . . . . . . .

Ginna (NY). . . . . . . . . . . . .

North Anna 1 (VA)... . . . .

North Anna 2 (VA)... . . . .

Peach Bottom 3 (PA). . . . .

Robinson 2 (SC).. . . . . . . .

Washington Nuclear 2(WA).

Arkansas Nuclear 2 (AR). .

Brunswick 1 (NC). . . . . . . .

Brunswick 2 (NC).. . . . . . .

Dresden 3 (IL). . . . . . . . . . .

Maine Yankee (ME). . . . . .

Millstone 2 (CT).. . . . . . . .

Oyster Creek (NJ). . . . . . . .

755

507

503

825

1,055

605

495

495

825

1,051

1,075

836

67

772

515

470

911

908

1,035

683

1,100

858

767

754

773

870

863

610

1993

1995”

1995”

1996*

1996

1996

1996

1996

1997”

1998

1998

1999

1999

1999

1999

1999

1999

1999

1999

1 999’

1999

2000

2000

2000

2000

2000

2000

2000

NOTE: Units marked with an asterisk (’) have constructed or announced plans to construct ISFSIS to increase their onsite spent fuel

storage capacity. The projected closure years shown above, therefore,

may no longer apply to some or all of these units.

SOURCE: U.S. Department of Energy, Energy Information Administration, Spent Nuclear Fuel Discharges from U.S. Reactors 1991,

SR/CNEAF/93-01 (Washington, DC: February 1993), pp. 14-19.

under current plans by the end of the year 2000

(table 3-2).118 Although measures such as reracking of spent fuel assemblies can extend the

capacity of fuel pools somewhat, the number of

utilities that will have to construct independent

spent fuel storage installations (ISFSIs) in order

to continue operating is virtually certain to

increase. Dry storage facilities have been or are

planned to be constructed at several plants-both

those still operating and those undergoing or

planning decommissioning.

The direct costs of adding spent fuel storage

capacity represent a small but not negligible

percentage of other plant operational costs. For

example, the Baltimore Gas and Electric Co.,

operator of the two Calvert Cliffs plants, has

constructed an ISFSI for $24 million, with annual

operational costs of about $1.5 million. The

annualized cost represents less than 2 percent of

Calvert Cliffs operating costs.

Some States have been reluctant to allow ISFSI

siting, effectively representing a large indirect

cost. In the extreme, lack of spent fuel storage

threatens several operating plants with premature

closure in the next several years. For example,

Minnesota’s Northern States Power operates the

twin Prairie Island plants, which have operating

licenses expiring in 2011 and 2013, but current

storage capacity is sufficient only through 1995.

Out of concern that a requested dry storage

facility would become a de facto permanent

repository, however, the Minnesota Public Service Commission limited the utility to constructing

a facility that added only 7 more years of storage

capacity. 119 A state court decision further restricted ISFSI use, ruling that the State legislature

must approve any plans to store the fuel more than

8 years.120 In Wisconsin, similar concerns are at

118 U.S. Department of Energy, Energy ~orrnation Administration Spent Nuclear Fuel Discharges from U.S. Reactors 1991,

SR/CNEAF/93-01 (Washington, DC: February 1993), table 4, pp. 14-19.

119 I $NspG~~ Repfieve Fro~_esoQ PSC,’ The Energy Daily, vol. 20, No. 124, J~e 29, 1992, p. 1. See also 57 FederaIRegister343 19

(Aug. 4, 1992).

Im M~esoQ law prohibits IX rrnanent fuel storage within the State. ‘‘Court Decision on Prsrie Island Fuels Argument for Moving Waste, ’

Nucleonics Week, vol. 34, No. 25, June 24, 1993, p. 17.
Chapter 3-Economic Lives of Existing Nuclear Plants 199

issue in the decision to continue operation or

retire the Point Beach unit 2 nuclear plant.121

At present, the DOE is planning to construct a

single national monitored retrievable storage

(MRS) facility to store commercial spent fuel

until a repository is available. Until that happens,

however, an increasing number of de facto

MRSs—in the form of dry cask storage installations built at reactor sites—will be necessary,

both for many plants to continue operating after

2000 and for decommissioning to occur.

Beyond development of a repository, some

treatment methods such as transmutation and

reprocessing for spent fuel are under development

here and abroad but face major technical, economic, or political obstacles.122

LLW disposal costs have increased rapidly in

the past and may continue to do so. However,

LLW disposal costs during plant operation currently represent a fraction of 1 percent of the

operational costs of nuclear plants. Even with the

much higher disposal costs anticipated under the

interstate compacts, LLW costs would average

about 1 percent of operational costs. However, as

discussed in chapter 4, there remain unmet

challenges in developing LLW disposal facilities.

121 me Point ll~ch unit 2 decision also involves consideration of a major capital expense, replacemeflt of the ph@’S Steam genemtOrS.

Nucleonics Week, vol. 34, No. 25, June 24, 1993, p. 17.

122 For more ~o~tion on these ~d other sPnt fiel ~ea~ent options, see M. Holt ~d J.E. Mieke, Civilian Radioactive Waste

Management: ?’echnical and Policy Issues, 91-867 ENR (Washington DC: Congressional Research Service, Dec. 10, 1991); D. Gibson, “Can

Alchemy Solve the Nuclear Waste Problem?’ The Bulletin of Atomic Scientists, vol. 47, No. 6, July 1991, pp. 12-17; C. Ne~ Rockwell

International, International Programs Related to the Transmutation of Transuranics, EPRI NP-7265 (Palo Alto, CA: Electric Power Research

Institute, April 1991); and M. Odell, “Vitrification-World Review,” Nuclear Engineering International, vol. 37, No. 455, June 1992, pp.

51-53.
I

Decommissioning

Nuclear

Power

Plants 4

hen a nuclear plant is retired, decommissioning is

performed to protect both public health and safety

and the environment from accidental releases of

remaining radioactivity. As defined by U.S. Nuclear

Regulatory Commission (NRC) rules, decommissioning involves removing a reactor safely from service and reducing

residual radioactivity to a level that allows a site to be released

for unrestricted use, thereby allowing license termination. l

Under NRC rules, decommissioning activities—such as plant

decontamination, reactor dismantlement, and waste removal—

can be performed within a few years or extended over many

decades. Although current NRC rules favor the completion of

decommissioning within 60 years after final plant shut down, the

Commission will extend that period if necessary to protect public

health and safety.2 The lack of waste disposal capacity or the

presence of other nuclear units on a site are two circumstances

that could extend decommissioning periods beyond the current

60-year goal.3

Three general decommissioning approaches are recognized by

nuclear professionals in the United States: DECON, SAFSTOR,

and ENTOMB. The first approach, DECON, involves the

immediate dismantlement of radioactively contaminated structures to a level allowing the site to be released for unrestricted

use. SAFSTOR involves placing a nuclear plant into safe storage,

followed years or decades later by sufficient decontamination

and dismantlement to allow site release. The last approach,

ENTOMB, involves partial dismantlement followed by the

1 10 CFR 30.4, 40.4, 50.2, 70.4, and 72.3.

2

10 CFR 50,82 [b)(l)(i). If necessary to protect public health and safety, the U.S.

Nuclear Regulatory Commission (NRC) will extend the allowable decommissioning

period to about 100 years. 53 Federal Rrgisrer 24023 (June 27, 1988).

3 10 CFR 50.82 @)(l) (iii).

I 1

I 101
102 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

o

0

The oldest and smallest of the three units at the San

Onofre Nuclear Generating Station (at the far left of

the photo) was retired in 1992 after over 24 years of

operation. The presence of the two remaining

operating units is a factor considered in

decommissioning planning for unit one.

encasement of remaining radioactive contaminants in durable materials such as concrete and

monitoring a site until sufficient radioactive

decay has occurred to allow release for unrestricted use. The best approach will vary by plant

and depend upon site-specific conditions, such as

the level of radioactive contamination at shutdown, expected land uses, projected labor rates,

waste disposal options and costs, and current and

anticipated regulatory radioactivity standards.

Rather than technological adequacy, the

major uncertainties associated with commercial nuclear power plant decommissioning are

the potential impacts of future residual radioactivity standards, limited and dwindling waste

disposal options, and cost projections, the

reliability of which will improve with the

resolution of these other uncertainties. While

the technology exists to remove the radiological

hazard at individual plant sites, residual radioactivity standards have not been promulgated by the

NRC or the U.S. Environmental Protection Agency

(EPA). In addition, States may impose nonradiological cleanup requirements at sites (e.g., site

restoration) or perhaps additional radiological

requirements after NRC license termination. Moreover, the feasibility and costs of long-term

radioactive waste storage and disposal remain

unclear, both for low-level wastes (LLW) and

spent nuclear fuel. These factors create major

uncertainties in the anticipated schedules and

projected costs of decommissioning commercial

nuclear power reactors. With the recent retirement of several large operating reactors, this may

be an opportune time to evaluate the national

policies, regulatory standards, economics, public

concerns, and other uncertainties (particularly

waste disposal options) associated with commercial nuclear power plant decommissioning. For

example, the 40-year operations period assumed

for the collection of decommissioning funds has

proven optimistic for several plants and may be

optimistic for many others.

Although decommissioning costs are relatively

small compared to total plant capital and operations expenses, prematurely retired plants may

face significant decommissioning funding shortfalls, because they collected these funds for less

time than expected. Although financially healthy

utilities will generally be able to cover such

shortfalls through increased electricity rates, insurance, credit, and other options, there are

potentially serious intergenerational equity issues

associated with collecting the bulk of decommissioning funds after plant closure. That is, based

on current trends, future ratepayers may have to

cover most of the costs of commercial nuclear

power decommissioning without having received

any of the electricity from a retired unit.

RESIDUAL RADIOACTIVITY STANDARDS:

HOW CLEAN IS CLEAN ENOUGH?

Residual radioactivity standards define the

level of clean up necessary at sites undergoing

decommissioning. Depending on their nature and

stringency, such standards may have major impacts on decommissioning timing and costs,

waste generation, occupational and public health
Chapter 4–Decommissioning Nuclear Power Plants ! 103

and safety, and the potential future uses of

remediated sites.

Under current NRC decommissioning criteria,

sites eligible for unrestricted use may contain

some radioactivity above natural background

levels—no more than 5 additional microrems

(10-6 rems) of surface contamination per hour .

4

The NRC is currently developing a rule to

establish residual radioactivity standards, and

their ultimate nature and stringency could differ

substantially from the current, less formal guidance, potentially altering the expected scope and

costs of decommissioning. Possible residual radioactivity standards discussed during NRC public

meetings held in 1993 ranged from doses of 0.03

to 60 millirems (10-3 reins) per year, a difference

of three orders of magnitude. Based on the best

available evidence (see ch. 2), these dose levels

translate to lifetime cancer mortality risks ranging

from one case per million to two cases per

thousand exposed individuals, respectively.5 Until

final standards are promulgated, commercial

power licensees and the public will remain

uncertain about the residual health risks, cleanup

costs, and other impacts of decommissioning

nuclear power plants.

The practice of allowing low levels of residual

radioactivity after facility closure occurs at many

kinds of radiologically contaminated sites, including oil and natural gas drilling operations,

nuclear and coal-freed electric power stations, and

uranium and thorium mill tailing sites. Similar to

other site remediation efforts, including those for

containing hazardous chemicals, the potential

risk at nuclear sites under current NRC decommissioning criteria is reduced significantly but

not eliminated entirely.

Internationally, residual radioactivity criteria

are generally developed on a case-by-case basis

and are commonly based on safety guidance

published by the International Atomic Energy

Agency (IAEA).6 The IAEA guidance is riskbased, similar to existing NRC criteria, and finds

that an individual exposure limit of several

millirems per year from exempted materials

represents a sufficiently small risk. To account for

multiple exposure pathways (air, water, soil), the

IAEA guidance recommends a limit of 1 millirem

per year for each exempted practice. To date, most

European nations have applied the principles of

this IAEA guidance when setting residual radioactivity criteria for sites, but their major application has been in establishing recycling criteria for

radiologically contaminated materials, not in

decommissioning. 7

The negative U.S. public and political reaction

to the 1990 “below regulatory concern” (BRC)

policy may indicate potential problems with the

current NRC residual radioactivity criteria, as the

NRC pursues a rulemaking to establish uniform

remediation standards for decommissioning (box

4-A). Among other items, the 10 millirem annual

exposure limit was a key element of the controversial policy, but current NRC decommissioning

criteria of 5 microrem per hour above background

would allow an unshielded individual present at

the site 6 hours per day to receive roughly the

same added annual exposure. In terms of cancer

mortality, the best available evidence suggests

that an annual exposure of 10 millirems translates

4 This criterion applies to measurements made at 1 meter from the source, U.S. Nuclear Regulatory Cornmis sio% Terminan”on of Operating

Licenses for Nuclear Reactors, Regulatory Guide 1.86, June 1974, p. 5; and “Radiation Criteria for Release of the Dismantled Stanford

Research Reactor to Unrestricted Access, ’ NRC letters to Stanford University, Mar. 17, 1981 and Apr. 21, 1982. For a discussion of these

guidance documents, see U.S. Nuclear Regulatory Commissioq Office of Nuclear Regulatory Research Final Genen”c Environmental Impact

Statement on Decommissioning of Nuclear Facilities, NUREG-0586 (Washiugtoq DC: August 1988), p. 2-12.

5

58 Federal Register 33573 (June 18, 1993).

h International Atomic Energy Agency, Principles for the Exemption of Radiation Sources and Practicesfiom Regulatory Control, Safety

Series No. 89 (Vienna, Austria: 1988).

7 U.S. Nuclear Regulatory Commission “International Decommissioning Activities, ” unpublished paper.
104 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Box 4-A-Residual Radioactivity Standards and the

NRC Enhanced Participatory Rulemaking

An enhanced participatory rulemaking to develop residual radioactivity standards was first proposed by the

U.S. Nuclear Regulatory Commission (NRC) in June 1991. While many rulemaking efforts solicit public input after

a standard or guideline has been proposed, the NRC is using this process to solicit comments from affected parties

in advance of a rule proposal. To enhance participation, the NRC held seven public meetings between January

and May 1993 in different regions of the United States (Chicago, San Francisco, Boston, Dallas, Philadelphia

Atlanta, and Washington, DC). The meetings provided a forum to hear public concerns relating to residual

radioactivity standards, including their nature and stringency. Under its current schedule, the NRC expects to

publish final residual radioactivity standards by May 1995.1

The rulemaking on residual radioactivity standards has emerged from failed attempts in the last several years

to determine when either licensed materials or sites warranted no further regulatory attention due to sufficiently

low levels of radioactivity. The history began with the passage of the Low-Level Radioactive Waste Policy

Amendments Act of 1985 (P.L. 99-240; LLRWPAA), which directed the NRC to determine a threshold of

radioactivity in waste streams below which regulatory concern was not warranted.2 In response to that legislation,

the NRC published two below regulatory concern (BRC) policy statements (1986 and 1990). The 1986 statement

outlined criteria and procedures for the expedited review of BRC petitions to exempt materials from the standard

requirements for low-level waste management and disposal.3 In 1990, the NRC published the second BRC policy

statement that proposed individual dose criteria between 1 and 10 millirems (mrem) per year and a collective dose

criterion of 1,000 person-rem per year.4

In establishing these BRC criteria-about 0.3 to 2.8 percent of current annual U.S. background exposure

levels of 360 mrem--the NRC reasoned that the levels were comparable to levels of radiological risk normally

accepted by the public (both voluntarily and involuntarily) from other activities (e.g., 5 mrem is a typical exposure

for roundtrip flights between the east and west coasts of the United States). The NRC noted that far greater

variability than 1 to 10 mrem occurs from natural background exposures in different U.S. regions, such as a

difference of over 60 millirems for residents of Denver, Colorado compared to those of Washington, DC.5

1 Francis Cameron, C)ffice of the General Counsel, U.S. Nueiear Regulatory hmmkdon, puNic statement

during NRC participatory rulemaidng meeting, Arlington, VA, May 6,1993.

E PUMIC bW 99-240,99 Stat. 1859, Sec. IO(a).

351 Federal Register30839 (Aug. 29, 1986).

455 Fedgra/ Re@ter27522 (Juiy 3, IggO).

555 Fe@r# Re@ter27526-27527 (Juiy 3, 1990).

to an incremental annual risk of five cases per many cases, the levels of residual radioactivity

million individuals and a lifetime risk (assuming implied by current NRC guidance maybe acceptcontinuous exposure at that level) of about 4 cases able if site access and use are restricted. In other

per ten thousand.8 Depending on the site, how- cases, State, local, or public concerns about future

ever, States, local authorities, and the public may land uses at decommissioned sites may overhave different expectations about acceptable lev- shadow regulatory decisions over the selection of

els of residual radioactivity and health risks. In any quantitative radioactivity standards.

s 55 Federal Register 27527 (]tdY 3, 1990).
Chapter 4–Decommissioning Nuclear Power Plants I 105

Severe public and congressional reaction to the July 1990 BRC proposal prompted the NRC to place an

indefinite moratorium on the policy statement shortly after it was issued. In particular, testimony delivered at

congressional hearings held the same month the policy was issued indicated several major concerns about the

BRC policy, including the potential to pre-empt State authority to establish more stringent standards, a concern

that a great deal of BRC material could be disposed of in ordinary landfills, the lack of clear assurances that the

NRC would be able to track and enforce compliance, and the fact that the maximum allowable exposure from

releasable materials (10 mrem) was two and one-half times the U.S. Environmental Protection Agency (EPA)

drinking water standard (4 mrem).6Two years later, the Energy Policy Act of 1992 revoked the NRC’s BRC policy

statements entirely.7

After placing the initial moratorium on the BRC policy statements, the NRC proposed a “BRC consensus

process” in 1991 to convene representatives from major groups interested in the development and implications

of a BRC policy. That process, however, was canceled several months later when a major environmental group

declined to participate.

With regard to decommissioning, three of its most important aspects are affected directly by BRC-type criteria,

whether pre-established by formal standards or ad hoc:

1. The residual radioactivity levels that determine when a site can be released for unrestricted use (the

current goal of decommissioning);

2. The amount of radioactive waste requiring special disposal; and

3. The extent to which slightly contaminated material maybe reused or recycled in general commerce.

By March 1992, the NRC decided to abandon a generic BRC approach and develop instead specific

standards for different licensee activities-such as residual radioactivity standards for decommissioning-in

separate rulemakings. Therefore, the moratorium on the BRC policy statements and the termination of the BRC

consensus process led to the separate treatment of residual radioactivity standards in the current enhanced

participatory rulemaking.

ADDITIONAL SOURCES: 57 Federa/ Re@ster 58727-58730 (Dec. 11, 1992): 10 CFR Part 20, Radiological

Criteria for Decommissioning of NRC-Licensed Facilities; Workshops.

U.S. Nuclear Regulatory Commission, Office of the General Counsel, “Proposed Rulemaking To Establish

Radiological Criteria For Decommissioning: Issues For Discussion At Workshops,” unpublished paper.

U.S. Nuclear Regulatory Commission, “Briefing on Rulemaking Process for Developing Residual Radioactivity

Standards for Decommissioning,” Mar. 11, 1992, unpublished briefing transcript.

G See various testimony at hearings before the House Subcommittee on Energy and the Environment,

Committee on Interior and Insular Affairs, Hearings on the Nuclear Regulatory Commission’s Beiow Regulatory

Concern (BRC) Poiicy, Juiy 26, 1990, Serial No. 101-29.

7 PLJMC btw 102-466, 106 Stat. 3122, Sec. 2901(b).

Public acceptance of minimal radioactive re- tive releases are prescribed and enforced, such as

leases at operating nuclear facilities suggests that the release of small quantities of tritium to local

low levels of radioactivity are less of a concern if surface water. Such releases have been made at

land use is restricted and regulatory oversight is plant sites for decades,9 but there has been no

maintained. For example, in the context of major, visible public effort to ban them.

commercial nuclear power operations, regulatory Even with restricted land uses and some

criteria specifying acceptable levels of radioac- maintenance of regulatory oversight, however,

9 Kemeth Carr, Chairmaq U.S. Nuclear Regulatory Commission, testimony at hearings before the House Subcommittee on Energy and

the Environment, Committee on Interior and Insular Affairs, July 26, 1990, Serial No. 101-29, p. 85.
106 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

the public may have concerns about the consistency of residual radioactivity standards for

decommissioning with other Federal and State

radiological standards. For example, the current

EPA standard for residual radioactivity at inactive

uranium processing sites (40 CFR 192.12) is four

times higher (at 20 microrems per hour above

background levels) than current NRC criteria for

decommissioned nuclear power plant sites. In

addition, many view the regulatory risk goals for

limiting cancer risks after radiological cleanups

as inconsistent with those for hazardous chemical

cleanups. 10 Such discrepancies—perceived or

real--could complicate the development and

implementation of future residual radioactivity

standards and decommissioning plans.

The NRC is pursuing an “enhanced participatory rulemaking” to develop formal residual

radioactivity standards for decommissioning.11

Issues raised during public meetings include the

following:

whether to allow restricted land uses at some

sites as an alternative to unrestricted release;

ensuring consistency between proposed standards and existing federal health and safety

regulation;

determining the appropriate level and distribution of radiological and nonradiological risks

from decommissioning, LLW disposal, and

waste transportation;

determining the nature of licensee responsibility for residual radioactivity after a license is

terminated; and

ensuring the development of clear testing

criteria and the existence of adequate technology to measure and verify compliance with

any promulgated standards.

By addressing these concerns, the NRC will

improve the likelihood that States, local authorities, licensees, and the public will accept future

residual radioactivity standards. In addition, the

role and legal authority of both the NRC and the

EPA, if any, at retired plant sites may require

clarification, particularly in case additional cleanup

is required after an NRC license has been

terminated. Understanding the regulatory roles of

both the NRC and the EPA after site release may

be critical to participating States, local authorities, licensees, and the public as residual radioactivity standards are developed. In general, if

Federal agencies exercise no role or appear to

have little or no authority at plant sites after

license termination, many parties may expect

more stringent cleanup levels than might otherwise be selected.

Under the current regulatory definition, the

only expected outcome of decommissioning is

license termination and site release for unrestricted use (e.g., 10 CFR 50.2). In some cases,

however, cleanup to a level suitable for unrestricted use may be neither necessary for public

health and safety nor economically desirable,

because the expected radiation exposures at a

decommissioned power plant site will vary depending on its subsequent use. For example,

agricultural activities at released plant sites would

introduce different exposure pathways and doses

than residential use of the same area.12 Rather

than introduce the added occupational risk and

economic cost of remediating a site to permit any

activity whatsoever (such as farming ), a better

option at some sites maybe remediation to a level

allowing restricted use for select activities, such

as continued power production, provided that

future exposures from those activities will com10 See, for e=ple, S.L. Brow-q ‘‘Harmonizing CherniCal and Radiation Risk h-lanagemen~’ Environmental Science and Technology, VO1.

26, No. 12, 1992, pp. 2336-2338.

1157 Federal Register 58727-58730 @k. 11, 1992).

12 W.E. Kennedy, Jr., D.L. Strenge, Battelle Pacific Northwest Laboratory, Residual Radioacn”ve Contamination From Decommissioning:

Technical Basis for Translating Contamination Levels to Annual Total Effective Dose Equivalent, NUREG/CR-5512, vol. 1 (Washington DC:

U.S. Nuclear Regulatory Comrnissionj October 1992).
Chapter 4–Decommissioning Nuclear Power Plants I 107

ply with regulatory goals and standards for the

protection of public and occupational health and

the environment.

Power plant sites are developed industrial

facilities, generally located near water, transport,

and electrical infrastructure. As a result, some

sites may be better-suited for further power

production or other industrial activities, rather

than other uses such as farming or public recreation. Therefore, remediating a site to allow future

uses that are unlikely to occur may be unwarranted from a health protection or economic

perspective. At the same time, States, local

authorities, and the public may accept or prefer

restricted land uses or access at some former

nuclear facility sites based on concerns about

health and safety from any residual radioactivity

on site.

To increase the options to perform site cleanups that protect public health and the environment

and that are economically feasible, alternatives to

unrestricted use may be worth considering, such

as restricted use for other industrial purposes,

Thus, more than one decommissioning goal

(unrestricted use) and more than one residual

radioactivity standard may be appropriate. Given

the extended periods allowed for some decommissioning methods (SAFSTOR, ENTOMB),

restricted use is already practiced at many sites

with retired nuclear plants. That is, current

regulations allow an extended period of restricted

use before final site release, and the concept may

be worth extending beyond license termination.

Residual radioactivity standards have implications for both radiological and nonradiological

risks during and after decommissioning. Similar

to most hazardous chemical remediation, nuclear

decommissioning does not eliminate, but rather

isolates and transfers, contaminants from one site

(such as a nuclear power plant, a research

laboratory, or a medical clinic) to another (the

treatment, storage, or disposal sites). Decommissioning crews operate a variety of electrical and

mechanical equipment to decontaminate and

demolish retired facilities, while waste transport

to disposal sites adds risks to haulers and other

people living beyond the plant site.

Each unit of radiological contamination removed from a site, therefore, confers both radiological and nonradiological risks on and offsite.

As a result, the nature and stringency of residual

radioactivity standards will determine how much

material will require isolation and transport and

will affect the balance of total radiological and

nonradiological risks associated with decommissioning. As these comments suggest, decisions

about ‘‘how clean is clean enough? are fundamentally decisions about the acceptable levels

and distribution of the risks associated with

decommissioning.

Other important aspects of residual radioactivity standards are measurability and verification,

which become increasingly difficult as standards

become more stringent, particularly in the range

of a few millirems or less.13 Background radiation

levels on any land area may vary several millirems or more, depending on the exact location

sampled, its geology, and the weather. Therefore,

measuring and verifying compliance with residual radioactivity standards may be difficult and

may affect decommissioning practicability and

project costs if their stringency approaches background levels. Such stringent cleanup levels may

also compel some licensees to remediate site

radioactivity associated with previous, allowed

releases.

Finally, residual radioactivity standards may

have substantial impacts on final decommissioning costs, because they will determine the amount

of material requiring removal and disposal. The

current NRC financial assurance rules (discussed

below), as well as most cost estimates performed

by private contractors, assume final residual

radioactivity levels given in the current NRC

13 wiui~ Dornsife, Director, Bureau of Radiation Protection, Penmylvania Department of Environmental R~SOI-WmS, pemo~

communication, May 6, 1993,
108 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

guidance, but those levels may change in the

future. At present, estimates of decommissioning

costs typically assume residual radioactivity standards no more stringent than about 10 millirems

per year,

14 the level specified in the now revoked

BRC policy, but the NRC, States, local authorities, or the public may expect more stringent

standards in the future.

RADIOACTIVE WASTE DISPOSAL

The essential challenge of decommissioning is

to remove and dispose of radioactive waste, while

keeping occupational and other exposures as low

as possible. There are three major classes of

commercial nuclear plant waste, based on the

composition and radioactivity of the materials

involved: LLW, mixed LLW, and high-level

waste (HLW).15 All three kinds of waste are

generated from both operating and decommissioning nuclear power reactors. LLW represents

more than 99 percent of the volume of all

commercial nuclear waste but less than 0.1

percent of the total radioactivity. Spent nuclear

fuel, on the other hand, the only HLW form in the

commercial nuclear power industry, represents

less than 1 percent of the volume, but more than

99.9 percent of the radioactivity, of commercial

nuclear waste.16 The other major class, mixed

waste, is a special subset of LLW composed of

both radioactive and hazardous chemical elements, which poses a special problem for Federal

regulators (discussed below).

Waste disposal is a major portion of expected

decommissioning costs. The estimated cost of

shipping and disposing LLW is over one-third of

the total estimated cost of DECON (immediate

dismantlement) decommissioning for very large

(more than 1,100-megawatt (MW)) electric light

water reactors .17 This section reviews the classification of major decommissioning wastes, projections of the amounts generated, and disposal

options.

B Low-Level Waste

The Low-Level Radioactive Waste Policy Act

(Public Law 96-573; LLRWPA) and the LowLevel Radioactive Waste Policy Amendments

Act of 1985 (Public Law 99-240; LLRWPAA)

defined LLW by what it is not: radioactive waste

not classified as HLW, spent nuclear fuel, or

14 see, for ~xmp~e, U,S. Nuclear Re@a@~ commissio~ (Mice of Nuclear Regulatory Researc4 Final Generic ~nvi~onmenfd ~mPacr

Statement on Decommissioning of Nuclear Facilities, NUREG-0586 (Wa.sMngtoQ DC: August 1988), pp. 2-12 to 2-13.

15 Two ~~erclasses of r~loactive wmt~m~u mill tailings and transuranic wast+-existbut are not =SOCtit~ witi commerci~ nucle~

power plant decommissioning and consequently are not discussed in this report. (Uranium mill tailings aregenerated by uranium ore processing

and contain very low radioactivity. Transuranic (T’RU) waste also contains very low radioactivity (akin to LLW) and is composed of long-lived

radioactive elements heavier than uranium (hence the name); TRU waste is mostly plutonium and derives almost exclusively from nuclear

weapons production,) M. Holt and J.E. Mielke, Civilian Radioactive Waste Management: Technical and Policy Issues, 91-867 ENR

(Washington DC: Congressional Research Service, Dec. 10, 1991), pp. 4,27.

lb At tie end of 1991, tie sum of commerci~ LLW disposed of historically in the United States amounted to 1.4 milfion cubic rnete~ wlti

a total activity of about 5.7 million curies. By compariso~ commercial spent fiel volumes totaled about 9,500 cubic mete~, with a total activity

of 23.2 billion curies. U.S. Department of Energy, Integrated Data Base for 1992: U.S. Spent Fuel and Radioacfi”ve Waste Inventon”es,

Projections, and Characteristics, DOE/RW-0006, Rev. 8 (Washingto~ DC: October 1992), pp. 9, 14. A curie (Ci) is a common measure of

radioactive decay, representing 37 billion disintegrations per second.

IT me est~te Vfies depend~g on whether the reactor is a BWR (34 pement) or a PWR (38 percent). G.J. Komek ~d R.I. Smit4 Battel~e

Pac~]c Northwest Laboratory, Technology, Safety and Costs of Decommissioning a Reference Boiling Water Reactor Power Station: Technical

Support for Decommissioning Matters Related to Preparation of the Find Decommissioning Rule, NUREG/CR-0672, Addendum 3

(Washington, DC: U.S. Nuclear ReguIato~ Commission, July 1988), p. 3,1; and G.J. Konzek and R.I. Smith+ Battelle Pacific Northwest

Laboratory, Technology, Safety and Costs of Decommissioning a Reference Pressurized Water Reactor Power Station: Technical Support for

Decommissioning Matters Related to Preparation of the Final Decom”ssioning Rule, NUREG/CR-0130, Addendum 4 (Washingto~ DC:

U.S. Nuclear Regulatory Commissio~ July 1988), p. 3.1. As shorthant the NRC study reactors are referred to as the “reference reactors” in

this report. The cost estimates shown here represent the shipment and disposal of all LLW and the shipment only of spent fuel. Delays in

developing a national geologic repository for commercial spent fuel, however, may require many licensees to construct interim storage capacity

on their sites, an unanticipated and costly enterprise discussed in more detail inch. 3.
Chapter 4-Decommissioning Nuclear Power Plants I 109

uranium or thorium mill tailings and mill wastes

is LLW.18 Roughly 92,000 cubic meters (m3

) (or

3,249,000 cubic feet (ft3

)) of LLW are disposed

annually in the United States. Most (about 58

percent) stems from U.S. Department of Energy

(DOE) activities, including defense programs,

uranium enrichment, naval propulsion, and research and development (R&D) projects (figure

4-l). Commercial nuclear power production—

including uranium conversion, fuel fabrication,

and power plant operations—accounts for another 33 percent. Other commercial enterprises,

such as radiochemical manufacturers, laboratories, hospitals, universities, and medical schools,

account for the remaining 9 percent. 19

LLW is produced during nuclear power plant

operations, repair and maintenance outages, and

decommissioning (box 4-B). In 1990, operating

pressurized water reactors (PWRs) in the United

States disposed an average 108 m3 of solid LLW,

less than one-fifth of the 1980 average (figure

4-2). The same year, operating boiling water

reactors (BWRs) disposed an average 301 m3 

o f

solid LLW, less than one-third of the 1980

average (figure 4-3). 20 Typical solid LLW includes contaminated worker clothing, gloves,

equipment, and tools. Operating plants also

generate some wet LLW, which consists of spent

ion exchange resins (used to regenerate chemical

decontaminants), plant sludges, and evaporator

concentrates. 21

Figure 4-l-Sources of Low-Level Waste

in the United States, 1991

Commercial

reactors

30,590 m3

(33%)

Other

commercial

8,190 m3

(9%)

SOURCE: U.S. Department of Energy, Irrbgrated Data Base for 1992.’

U.S. Spent Fuel and Radioactive Waste Inventories, Projections, and

Characteristics, DO13RW-0006, Rev. 8 (Washington, DC: October

1992), pp. 117, 121.

Rising disposal costs in the 1980s spurred

LLW volume reductions, largely from waste

compaction and improved management (waste

segregation, storage, evaporation, and incineration). 22 Between 1980 and 1991, annual commercial LLW disposal volumes decreased from

about 100,000 m3 (3.5 million ft3

) to 34,000 m3

(1.2 million ft3),23 even with the addition of many

new nuclear power plants, the major source of

commercial LLW.

The NRC distinguishes four LLW types,

ranked by increasing radioactivity: Class A, Class

1842 U.S ,C. 202 l(b).

1 q U.S. D~pc~cn[ of Energy, Inteqrff[ed Data Base for 1992. US. Spent Fuel and Radioactive Waste Irrverrron”es, projection, und

Characrerzstics, DOE/RW-0006, Rev, 8 (Washington, DC: October 1992), pp. 117, 121. Cubic meters are converted to cubic feet by dividing

the former by 0.0283168.

‘“ Institute of Nuclear Power Operations, ‘‘1990 Perfo rmance Indicators for the U.S. Nuclear Utility Industry’ (Atlanta, GA: March 1991).

Note: More recent figures for LLW produced by commercial power plants are available from INPO but are no longer given as averages,

preventing simple comparisons with earlier data, As a result, the more recent figures are not given here.

~1 S.W. Long, The Incineration of bw-Le>elRadioacti>te Waste: A Report for the Advisory Committee on Nuclear Waste, NUREG-1393

(Wwhirrgton, DC: U.S. Nuclc.ar Regulatory Commission, June 1990), p. 2.

‘z See, for example, U.S. Department of Energy, Office of Environmental Restoration and Waste Management, 199Z Annual Report on

b~-fxnef Radioacti\’e Waste Management Progress, DOE/EM-0091P (Washington, DC: November 1992), pp. B-3 to B-4.

~q W.R, Hcndcc, ‘‘Disposal of Low-Level RadioaAivc Waste: Problems and Implications for Physicians,’ Special Communication% Journal

of the Amcricuri Medical A~sociation, vol. 269, No. 18, May 12, 1993, p. 2404.
110 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Box 4-B—Low-Level Radioactive Waste and Decommissioning

Three general groups of low-level waste (LLW) stem from decommissioning power reactors. Neutronactivated materials generally contain significant quantities of long-lived radionuclides, particularly nickel-59

(75,000-year half-life), nickel-63 (100-year half-life), and niobium-94 (20,300-year half-life). Materials are activated

when neutrons dispersed from the fission reaction collide with trace metals in their structures. A reactor pressure

vessel (RPV), its internal components, and the surrounding concrete biological shield are the major plant

components that undergo activation.’

Even after 40 years of operation, a RPV and its concrete biological shield will generally rank as Class A LLW,

though some reactor internals--incore instrumentation, upper and lower guide structures, pressurized water

reactor (PWR) control rod assemblies, boiling water reactor (BWR) control rod blades-may undergo enough

activation to rank as high as greater-than-Class-C (GTCC) waste.2 In cases where plant operations were short

(such as Shoreham) or availability was low (such as Fort St. Vrain), neutron-activation will be less significant, and

the existing waste will generally be classified low (e.g., Class A). Alternatively, where operations were far longer

(15 to 20 years), total plant radioactivity actually levels off, because of the short half-life (5 years) of cobalt-60,the

major contaminant in operating plants.

Contaminated materials are standard materials such as steel and concrete that contain or have embedded

trace amounts of short-lived radionuclides, all of which are neutron-activated materials. In general, contamination

is caused by the settling or adherence of activated products on internal surfaces such as piping. While

contaminated materials can be cleaned (i.e., decontaminated), activated materials must be removed by structural

disassembly. The most common radionuclides in contaminated materials are cobalt-60 {5-year half-life) and

cesium-137 (30-year half-life), although some long-lived radionuclides maybe involved as well. Most of the piping

and equipment and much of the concrete in the buildings containing and surrounding the reactor vessel become

contaminated from power operations. These structures include the containment, fuel, auxiliary, control and, in the

case of BWRs, turbine generator buildings. The average concentrations of the short-lived radionuclides

contaminating these structures is generally low enough to rank their materials as Class-A LLW.3

The last general group of decommissioning waste, other radioactive waste, is composed of materials that

become contaminated when they are used by plant workers, such as gloves, rags, tools, plastic sheeting, and

chemical decontaminants. Like conventional contaminated waste, other radioactive waste is largely composed of

the same short-lived radionuclides (cobalt-60 and cesium-137), with perhaps some small portions of long-lived

radioisotopes, The distinction made between contaminated and other radioactive waste is worth noting, however,

because the latter is not part of the original physical plant (concrete, piping, reactor vessel, turbines) and needs

to be managed differently because of its mobility. Such radioactive waste is generally Class A, although as much

as 25 percent by volume may qualify as Class B.4

1 E*S. Mu@y, T~no/~y, SafefyandCosts of Decommissioning a Refirence Prewudzed ~terReacfor

Power statbn: C/asslficat/onof Decon?mkioning Wastes, NUREG/CR-0130, Addendum 3 (Washington, DC: U.S.

Nuofear Regulatory Commission, September 1984), p. 2.1. Half-life information Is from U.S. Department of Energy,

Integrated Data &se for 1992: LLS. Spent Fue/and Radbactive Waste hwntoriesp %@tions, and Characteristics, DOE/RW-0006, Rev. 8 (Washington, DC: October 1992), app. B, pp. 255-261.

2 Thomas S. UGuanji~ President, TLG Engineering, letter to the Offioe of T~ology ASW3sm~t, Jan. 22, Iggs.

3 l~d,; and Eosd Murphy, Battefle p~ific Northwest Lahratory, T&#mo&Y, %ety and c08ts Of

Decommissionh?g a Referen@ Boiling Water Reactor Power Station: Clkwsifioation of Decommissioning tMastes,

NUREG/CR-0672, Addendum 2 (Washington, DC: U.S. Nuclear Regulatory Commission, September 1984), p. 2.1.

Note: The turbine generator buitding in BWRS becomes contaminated by the direct flow of reactor coolant water to

the turbines, a unique aspect of BWR design that allows greater generation effidency relative to PWRS. Such flow

does not occur in PWRS, where steam generators heat water in a secondary Imp that drives the turbines. However,

steam generator leaks, often from ruptured or cracked tubes, oan lead to PWR turbine contamination.

4 Ibid., p. 2.2.
Chapter 4-Decommissioning Nuclear Power Plants I 111

Figure 4-2—Solid Low-Level Waste Volumes

From Operating Pressurized Water Reactors in

the United States, Annual Averages, 1980-1990

700 T

600< ~6 575

500

100

481

459

Figure 4-3-Solid Low-Level Waste Volumes

From Operating Boiling Water Reactors in the

United States, Annual Averages, 1980-1990

“400~ 1

1 ,200 +,, CJ

o

1980 82 84 86 88 90 1980 82 84 86 88 90

SOURCE: Institute of Nuclear Power Operations, “1 990 Performance

Indicators for the U.S. Nuclear Utility Industry” (Atlanta, GA: March

1991).

B, Class C, and greater-than-Class C (GTCC).24

Classification depends on the type and concentration of the radionuclides present, which are

determined by site-specific conditions, such as

the duration of power operations and the amount

of activated trace metals (such as nickel and

copper) contained in the reactor and steam supply

system. Class A waste contains the least radioactivity and represents the lowest risk to public

health and the environment. Most of the piping,

concrete, and equipment located in a nuclear

power plant will qualify as Class A waste,

including significant portions of a reactor pressure vessel. Other common Class A wastes

SOURCE: Institute of Nuclear Power Operations, “1990 Performance

Indicators for the U.S. Nuclear Utility Industry” (Atlanta, GA: March

1991).

include contaminated tools, worker clothing, and

protective plastic sheeting.25

Class A waste represents about 97 percent of

total commercial LLW volumes, emits very little

heat and radiation, requires no special shielding to

protect workers or the public, and remains harmful for about one century. Classes B and C waste

remain harmful for 300 to 500 years, while GTCC

waste is harmful for several hundred to several

thousand years.26

While Class A waste comprises almost the

entire volume of commercial LLW disposed

annually, its total radioactivity is relatively small.

This highlights a general, though not absolute,

~ 10 cm 61.55.

23 E.S. Murphy, Battelle Pacific Northwest Laboratory, Technology, Safety and Costs of Decommissioning a Reference Pressurized Water

Reactor Power Srarion: Classification of Decommissioning Wastes, NUREG/CR-0130, Addendum 3 (Washington DC: U.S. Nuclear

Regulatory Commission, September 1984), pp. 2.1-2.2, 6.3-6.9; and E.S. Murphy, Battelle Paciilc Northwest Laboratory, Technology, Safety

and Costs of Decommissioning a Reference Boiling Water Reactor Power Station: Classijcation of Decommissioning Wastes,

NUREG/CR-0672, Addendum 2 (Washington DC: U.S. Nuclear Regulatory Commission September 1984), pp. 2.1-2.2,6.3-6.9.

‘h U.S. Congress, Office of Technology Assessment Partnerships Under Pressure: Managing Commercial Low-Level Radioactive Waste,

OTA-O-426 (Washington, DC: U.S. Government Printing OffIce, November 1989), p. 81; and U.S. Congress, Office of lkchnology

Assessment, An Ei’aluation of Options for Managing Greater-Than-Class-C Luw-L.evel Radioactive Waste, OTA-BP-O-50 (Washington DC:

October 1988), p. 38.
112 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Figure 4-4-Projected Low-Level Waste Volumes

From Decommissioning a Reference Pressurized

Water Reactor as a Function of Storage Period

*() ~ - ------ –

7.88

—

17.888 _ GTCC

7

~ Class C

I

~ Class B

m Class A

3.06

1.83 1.78

I

DECON 30-year 50-year 100-year ENTOMB

SOURCE: E.S. Murphy, Pacific Northwest Laboratory, Teclrncdogy,

Safety and Costs of Decommissioning a Reference Pressurized Water

Reactor Power Station: Classification of Decommissioning Wastes,

NUREG/CR-01 30, Addendum 3 (Washington, DC: U.S. Nuclear Regulatory Commission, September 1984), p. 2.3, 4.3.

characteristic of LLW: the greater health and

environmental risks are posed by waste classes

possessing the lower total volumes, most notably

GTCC waste. This is particularly important to

appreciate about decommissioning waste, where

the great volumes of several LLW classes account

for far less radioactivity than the less voluminous

but more active GTCC waste and spent nuclear

fuel.

LLW DECOMMISSIONING VOLUMES AND

DISPOSAL OPTIONS

According to NRC projections, decommissioning 1,1OO-MW light water reactors that have

operated their full 40-year licensed lives will

generate roughly 18,000 m3 (636,000 ft3

) of

LLW, about 98 percent of which is Class A

(figures 4-4 and 4-5). The NRC is currently

revising these estimates. ENTOMB produces

more LLW than 50- and 100-year SAFSTOR,

because the NRC estimate assumes dismantlement of the reactor internals prior to final

entombment in order to remove long-lived radionuclides in the vessel that would prevent site

release within a reasonable period (e.g., 100

years). An extended storage period prior to any

internals dismantlement and final entombment,

however, could possibly reduce total ENTOMB

LLW volumes, depending on the types, concentration, and distribution of radionuclides remaining after plant shutdown.

Based on current information, decommissioning a large commercial power plant may generate

more LLW than generated during its operations.

As suggested above, operating commercial nuclear power plants in the United States have

steadily decreased their LLW disposal volumes

for more than a decade. From 1980 to 1990, U.S.

operating PWRs generated average annual LLW

volumes of 336 m3 and operating BWRs 666 m3

,

but the actual amounts disposed in recent years

have been far lower.27 If LLW disposal volumes

from operating plants in recent years represent the

likely annual average over 40 years of operation,

DECON decommissioning will generate at least

50 percent more LLW than generated during plant

operations. Of course, LLW volume reduction

efforts during decommissioning may substantially lower the expected amounts of disposed

waste, but the development of residual radioactivity standards more stringent than current regulatory criteria would have the opposite effect.

As figures 4-4 and 4-5 suggest, waiting as

much as 50 years to dismantle a reactor is

expected to reduce final LLW volumes substantially—

90 percent for both PWRs and BWRs. Shorter

waiting periods have less of an effect; LLW

disposal volumes are virtually unchanged when a

30-year storage period is assumed. For both

PWRs and BWRs, 30 years of storage would

27 ~sti~te of Nuclear Power Operations, ‘‘1990 performan ce Indicators for the U.S. Nuclear Utility Industry’ (Atlan@ GA: March 1991).
allow a large portion of Class B waste to decay to

Class A status, but the volumes of other waste

classes (C and GTCC) would remain the same.

Under NRC rules, the frost three LLW classes

may be disposed by shallow land burial, although

packaging, transport, and disposal requirements

are progressively more stringent with each waste

class (A to C). Other disposal technologies

(reinforced vaults, modular concrete canisters,

concrete bunkers) are available but are more

expensive and have not yet been implemented.28

Through arrangements with the NRC, 29 States

(known as “Agreement States”) regulate these

frost three LLW classes, The last class, GTCC, is

not suitable for shallow land burial and must be

disposed of by the Federal Government in a

geologic repository (10 CFR 61), which is not yet

available.

The first LLW disposal site opened in Nevada

in 1962 (Beatty), and five more were operating by

1971. Three of these sites closed later in the

1970s,

29 and Beatty closed January 1993. As a

result, only two sites are in operation today:

Barnwell (South Carolina) and Richland (Washington). To encourage the development of more

LLW disposal facilities, Congress passed the

Low-Level Radioactive Waste Policy Act in 1980

(P.L. 95-573; LLRWPA), This statute directed

States to assume responsibility for LLW disposal

and encouraged the formation of regional interstate compacts to manage LLW. Compacts were

authorized to restrict LLW disposal access to their

member States beginning in 1986. At present, the

Richland site is restricted to members of the

Northwest and Rocky Mountain compacts, and

out-of-compact access to the Barnwell site will

continue until July 1, 1994. After that, Barnwell

access will be restricted to members of the

Chapter 4—Decommissioning Nuclear Power Plants

113

Figure 4-5-Projected Low-Level Waste Volumes

From Decommissioning a Reference Boiling Water

Reactor as a Function of Storage Period

25 F———

I

20 / 18.949 18.949

0

- GTCC

~~ Class C

~ Class B

~ Class A

1.783 1.673

I

PiIH1 I

1 ’

DECON 30-year 50-year 100-year ENTOMB

h

SOURCE: E.S. Murphy, Pacific Northwest Laboratory, Technology,

Safety and Costs of Decommissioning a Reference Boiling Water

Reactor Power Station: Classification of Decommissioning Wastes,

NUREG/CR-0672, Addendum 2 (Washington, DC: U.S. Nuclear Regulatory Commission, September 1964), p. 2.3, 4.3.

Southeast compact for 18 more months, at which

time the facility is scheduled to close.30

In 1985, with no new LLW disposal facilities

under development, Congress passed the LowLevel Radioactive Waste Policy Amendments

Act (P.L. 99-240; LLRWPAA). This legislation

postponed the allowable access restrictions to

1993 and authorized surcharges on LLW disposed by licensees belonging to any compact that

was failing to make progress towards opening

28 W,R. Hendee, ‘‘Dispos~ of ~w.~ve] ~dioactive Wwte: ~oblems ad ~pli@ions for Physicians, ’ Special Communication, Journa]

of the American Medical Association, vol, 269, No. 18, May 12, 1993, p. 2405.

29 ~e~e ~= ~ite~ ~ere ~ west ~q, New York (closed 1975); ~ey mats, Ken~cky (CIOS~ 1977); ad Sheffield, Illinois (closed

1978), U.S. Department of Energy, Integrated Data Base for 1992: U.S. Spent Fuel and Radioactive Waste Inventories, Projections, and

Characteristics, DOE/RW-0006, Rev. 8 (Wsshingtou DC: October 1992), pp. 132, 136.

30 C{BmWe]l Wrote site t. Rem opq’” Nuclear Engineering ]nternatio~l, VO1, 3’7, No. 458, September 1992, p. A.
114 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Barnwell, SC, and Richland, WA, are the two LLW

disposal facilities remaining in operation in the United

States. Barnwell (above) is scheduled to close in 1996,

and Richland (right) no longer accepts waste

generated outside the Rocky Mountain and Pacific

Northwest regions.

new disposal sites.31 In many cases, these surcharges have become greater than the nominal

disposal fee. For example, in 1990, the fees at the

three existing LLW disposal sites ranged from

$32 to $41 per ft3 for the least active waste.

Additional fees could be imposed, depending on

the waste phase (solid or liquid), weight, and the

surface radioactivity of the containing vessel.32

The authorized surcharge for noncompact licensees that same year, however, was $40 per ft3

,

which tripled to $120 per ft3 in 1992 for LLW

—- .

generators located within any State or compact

region that had failed to apply for a new LLW

facility by that time.33

The future amounts of both the LLW fees and

surcharges (as well as nonmember access to other

compact disposal sites) are two important uncertainties with projecting future LLW decommissioning disposal options and costs. Between 1978

and 1986, nominal LLW disposal fees increased

ten fold, from $3 to $30 per ft3 (excluding

surcharges and other fees) .34 Rates at new dis31 A ~rovi~ion of ~s sta~te ~trqfi~ s~tes without LLTV disposal options in 1996 to take title to waste generated MM tbeir borders

has been raled unconstitutional. New York v, United States, No. 91-543, June 19, 1992,

32 US, NUCle~ Re@atory co~ssio~ RepO~ on waste Burial Charges: Escalation of Decommissioning Waste Disposal Costs at

Low-Level Waste Burial Facilities, NUREG-1307, Rev, 2 (WashingtorL DC: July 1991), pp. A-1 to A-8.

33 ~w-~vel R@O~tive waste Policy Amendments Act (LLRWPAA), Public Law 99-240, 99 Stat. 1849, Sec. 5(d)(l)(C) md 99 Stat.

1854, Sec. 5(e)(2)(D).

~ R.I. Smith, Battelle Pacific Northwest bbomtory, “Potential Impacts of Extended Operating License Periods on Reactor

Decommissioning Costs,’ PNL7574 (Richlrmd, WA: Battle Pacific Northwest Laboratory, March 1991), p. 7.
Chapter 4–Decommissioning Nuclear Power Plants 115

posal sites are projected at $200 to $300 per ft3,

35

largely because the new facilities will have lower

disposal capacities but similar fried capital costs.

Currently, the minimum LLW disposal charge at

Barnwell for generators outside the Southeast

compact is $270 per ft3

.

36 Where LLW disposal

costs will stabilize remains a matter of speculation.

No new LLW disposal sites have been opened

since Barnwell began operating in 1971, more

than 20 years ago. Since then, no attempt to

license a LLW facility has yet succeeded, due to

legal, technical, or political reasons, including

efforts in California, Connecticut, Illinois, Michigan, Nebraska, New York, and Texas. 37 In part,

the experience at closed LLW disposal sites may

affect current public attitudes about new site

planning; the largest closed facility, Maxey Flats

in Kentucky, leaked enough contaminants within

a decade of its closure to qualify as an EPA

Superfund site in 1986.38 LLW disposal management and technologies have improved over the

last 20 years, but the level of public confidence in

the reliability and safety of candidate sites will

continue to affect the prospects of developing

them.

As an interim measure, several dozen nuclear

power licensees have constructed LLW storage

facilities at their plant sites, and more plan to do

the same.39 Beginning in 1996, however, NRC

rules discourage the use of onsite LLW storage.40

In the short term, onsite storage offers cost

savings for LLW management by allowing greater

radioactive decay of waste before final disposal.

In the long-term, though, extended onsite LLW

storage may lead to added radioactivity exposures

in several ways, including added worker handling, releases from storage containers, additional

monitoring requirements during storage, and

potential changes to container requirements between storage and final disposal, which could

necessitate additional waste handling.41 In addition, NRC rules governing LLW disposal facility

licensing (10 CFR 61.50) may prevent many

nuclear power sites from becoming permanent

disposal facilities, because power sites are generally located near major bodies of surface water

(rivers, bays, coasts), are likely to have high water

tables, and could disperse leaked contaminants

more readily than other areas more suitable for

permanent disposal,

GTCC waste is not suitable for near-surface

disposal and requires geologic burial (10 CFR

61.55). As discussed in box 4-B, some reactor

vessel internals are expected to undergo sufficient

activation over several decades of operation to

classify as GTCC waste. As with spent nuclear

fuel, the DOE is responsible for accepting and

disposing GTCC waste for the commercial power

industry, but there is no clear progress in develop35 Stqhen IN. solomo~ Twhnical Analys$ OffIce of State Programs, U.S. Nuclear Regulatory Commission, internal NRC memorandum

to Carleton Kammerer, Director, Offke of State Programs, Nov. 10, 1992.

36 RR. Zuercher, “Southemt Compact Commission Bars Central States’ Access to Bamwell, ’ Nucleonics Week, vol. 34, No. 16, Apr. 22,

1993, p. 11.

37 J. Cltie, ‘ ‘Deadlines Imom But No LLW Sites open Yet, ’ The Energy Daily, vol. 20, No. 204, Oct. 22, 1992, pp. 1-2; U.S. Congress,

General Accounting Office New York’s Adherence m Site Selection Procedures is Unclear, GAOIRCED-92-172 (Gaithersburg, MD: August

1992); R.R Zuercher, “Nebraska Officials Going Back to Beginning to Slow LLW Site Progress, ” Nuc2eonics Week, vol. 33, No. 21, May

21, 1992, pp. 8-9; R.R. Zuercher, ‘‘Proposed California Waste Site Mired in Election-Year Politics,’ Nucleonics Week, vol. 33, No. 20, May

14, 1992, p. 11; and U.S. Congress, General Accounting Office, Slow Progress Developing Low-L.evel Radioactive Waste Disposal Facilities,

GAO/RCED-92-61 (Gaithersburg, MD: January 1992), pp. 4, 18.

38 N. powell, “A Conumed Community: Plutonium Had Migrated Hundreds of Feet, ” EPA Journal, vol. 17, No. 3, July/August 1991, pp.

31-32.

39 L. Oyen ad R, Nelsoq s~gent & L~@ E@nWrs, Inten”m On-Sire Storage of ~w-k’el Waste, VO1. 2, part 2: S~eY of ‘iSting

On-Site LLW Storage Facilities, EPRI TR-1OO298 (Palo Alto, CA: Electric Power Research Institute, September 1992), p. 2-1.

@58 Federa[ Register 6735-6736 (Feb. 2, 1993).

AI 58 Federai Register 6731 (Feb. 2, 1993).
116 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

ing GTCC packaging, transport, and disposal

options. 42 As with spent fuel, therefore, operable

GTCC storage or disposal facilities are needed to

complete decommissioning work.

1 Mixed Waste

Also known as “mixed low-level waste,” this

waste is a combination of radioactive and hazardous chemical substances.43 Joint guidance established by the NRC and the EPA in 1989 defines

mixed waste as any waste containing both LLW

(as defined by the LLRWPAA) and hazardous

waste, as listed or characterized in 40 CFR Part

261. 44 The major groups of mixed waste generated

in commercial nuclear plants (and the activities

they are associated with) include organic compounds (laboratory counting tests and solvents

used to clean clothes, tools, equipment, and

instruments), waste oil (pumps and other equipment used in radioactive areas), metallic lead

(cont aminated when used for radioactive shielding), cadmium (welds and welding rods), and

chromates (corrosion inhibitors, resins) .45

MIXED WASTE DECOMMISSIONING VOLUMES AND

DISPOSAL OPTIONS

Mixed waste represents only a few percent of

annual LLW generation, and nuclear utilities

consider most of their mixed waste treatable.

While there are no national estimates of decommissioning mixed waste volumes, their expected

amounts are low relative to conventional LLW. In

1990, operating commercial nuclear power plants

in the United States produced an estimated 396

m

3 (14,000 ft3

) of mixed waste, about 10 percent

of the estimated amount from all sources that

year. The same year, nuclear utilities were storing

an estimated 623 m3 (22,000 ft3) of mixed waste,

primarily contaminated chlorofluorocarbons (39

percent), contaminated oil (23 percent), and

contaminated lead (20 percent). In the future,

material substitutions are expected to decrease

final disposal volumes.46 At present, there are

three commercial mixed waste disposal sites

(Colorado, Florida, and Utah), but their disposal

permits are restricted to select waste groups with

low activities.47

Part of the challenge with mixed waste management is regulatory: the NRC has authority

over the radioactive portion of the material, while

the EPA regulates the hazardous chemical portion. Under current EPA rules authorized under

the Resource Conservation and Recovery Act

(P.L. 94-580; RCRA), land disposal of hazardous

waste is restricted, but the only option currently

available for LLW disposal is shallow land burial.

Compared to problems with both LLW and HLW

disposal, mixed waste is a minor waste challenge

for operating nuclear plants, but the problem may

become more important as more licensees perform decommissioning and pursue license termination in the future. In the future, the DOE may

coordinate with States in the development of

42 Richard G, Ferre~a, Assistant Gener~ Manager, Sacramento Municipal Utility District, letter to the Office of Technology Assessmen4

Feb. 18, 1993. See also 1. SeliU “The Future for Low-Level Waste Disposal: Where Do We Go From Here?” Public Utilities Fortnight/y, vol.

131, No. 6, Mar. 15, 1993, p. 55.

43 Hi@-level w~te cm tiwi~ hazardous Waste as well, but the higher levels of radioactivity associated with that waste alorIe determine

its treatment. U.S. Department of Energy, Integrated Data Base for 1992: U.S. Spent Fuel and Radioactive Waste Inventories, Projecfi”ons,

and Characteristics, DOE/RW-0006, Rev. 8 (Washington DC: October 1992), p. 209.

44 “Res~ts of the Natio~ Profide on Commercially Generated Imw-Level Radioactive Mixed waste, ” unpublished paper presented to the

Advisory Committee on Nuclear Waste, U.S. Nuclear Regulatory Coremission, Nov. 20, 1992.

45 US, Congess, of fIce of llxhnoIogy Assessmen~ Partnerships Under Pressure: Managing Commercial Low-1-evel Radioactive Waste,

OTA-O-426 (Washington DC: U.S. Government Printing Office, November 1989), pp. 85-87.

46 J.A. ~e~ J.E. woche~ R.L. Jolley, I.W. C)sbome-be, A.A. Francis, and T. Wright, Oak Ridge National Laboratory, Nafionaf Profi”fe

on Commercially Generated Low-Level Radioactive Mixed Waste, NUREG/CR-5938 (Washington DC: U.S. Nuclear Regulatory

Commission, December 1992), pp. xiii, 2021,47,50-51.

47 Ibid., pp. 32-35.
Chapter 4–Decommissioning Nuclear Power Plants I 117

additional mixed waste treatment and disposal

capacity .48

The two facilities currently undergoing active

DECON decommissioning (Fort St. Vrain and

Shoreham) expect to generate no mixed wastes.49

These two cases, however, are probably anomalies; most plants retired in the future will

contain far more radioactivity from longer operations, increasing the probability that hazardous

materials will be contaminated with radiation.

Shoreham operated only for the equivalent of two

full power days and Fort St. Vrain, although it

operated 10 years, achieved only an average 15

percent capacity factor and was of a design

(helium gas-cooled) that limits plant contamination. Older, larger light water reactors that operate

longer will show far more radioactive contamination, increasing the likelihood of mixed waste

generation. In addition, higher levels of radioactivity increase the potential benefits of chemical

decontamination, a process that can generate

mixed wastes.

I High-Level Waste

Irradiated (spent) nuclear reactor fuel is the

only HLW generated by commercial nuclear

power plants.50 Spent fuel contains more radioactivity than any other form of commercial radioactive waste. The long-term public health and

environmental risks from spent fuel are of far

greater concern than LLW, because spent fuel

contains greater concentrations of long-lived

radionuclides, some with half-lives on the order

of tens of thousands of years and longer.51

SPENT FUEL WEIGHTS AND DISPOSAL OPTIONS

In recent years, total annual spent fuel discharges (measured in metric tons of initial heavy

metal) from operating U.S. reactors have amounted

to roughly 2,000 tons. The total amount of

discharged spent commercial fuel in the United

States (1968-1991) is nearly 24,000 tons.52 Before decommissioning can be completed at any

commercial facility, all spent fuel previously

discharged to the storage pool and any fuel still

present in the reactor vessel must be removed. As

discussed in chapter 3, however, the Federal

program to dispose spent fuel, as required under

the Nuclear Waste Policy Act of 1982 (P.L.

97-425; NWPA), has lagged. In addition to

affecting plant life decisions, the current inability

to dispose of spent fuel affects decommissioning

planning and implementation. Progress in developing interim HLW storage options (e.g., dry cask

installations, a Federal monitored retrievable

storage (MRS) facility) and a geologic repository

are discussed in chapter 3.

The development of a viable, long-term

management and disposal strategy for nuclear

waste will resolve not only major uncertainties

with decommissioning the first generation of

commercial nuclear plants but could influence

substantially the future prospects of developing a second generation of nuclear reactors in

48 U.S. Dep~ent of Energy, Department of Energy Strategy for Development of a National Compliance p!anfor DOE Mtied Wasle,

predecisional draft (Washington DC: November 1992), pp. 4, 20,24.

49 For more demils on these current decommissioning projects, S= boxes 4-C and 4-D.

50 me ~egulato~ def_~tion of ~W (10 cm W,2) also ficludes tie fiq~d and sofid wastes genemt~ by reprocessing spent fuel, but

reprocessing no longer occurs in the U.S. commercial power sector and is restricted to cleanup of the nuclear weapons complex. For a review

of defense HLW cleanup, see U.S. Congress, Offke of Technology Assessmen~ Complex Cleanup: The Environmental Legacy of Nuclear

Weapons Production, OTA-O-484 (Washingtorq DC: U.S. Government printing OffIce, February 1991); and U.S. Congress, Office of

Technology Assessment, Long-Lived Legacy: Managing High-Level and Transuranic Waste at the DOE Nuclear Weapons Compltx,

OTA-BP-O-83 (Washington, DC: U.S. Government Printing Office, May 1991).

51 For exmple, fie~-lives of Nickel-59, Niobium-94, and Iod~e-129, ~ comti~ents of commercial spent fue], are 75,0~; 20,300; and

15,700,000 years, respectively. U.S. Department of Energy, IntegratedData Basefor 1992: U.S. Spent FueiandRadioactive Waste Irr~3entories,

Projections, and Characteristics, DOE/RW-0006, Rev. 8 (Washington, DC: October 1992), pp. 280-289.

52 u.S. Department of Energy, Ener~ kformation Administratio& Spent Nuclear Fuel Discharges From U.S. Reactors 1991,

SR/CNEAF/93-01 (Washington, DC: February 1993), p. 21.
118 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

the United States. Unless viable disposal options

for both LLW and HLW are developed, utility and

financial planners and the public will remain

reluctant to invest further in nuclear power.

EXPERIENCE TO DATE

International decommissioning experience is

limited thus far to small reactors (250 MW and

less), which generally had short lives and relatively little contamination. Larger commercial

reactors that are being retired today, on the other

hand, typically will have operated longer and

have far higher levels of contamination. By 2015,

the licenses of over 40 operating plants (all but

one of them larger, older, and therefore more

contaminated than the early plants) may have

expired. 53 And based on current economic trends

in the nuclear utility industry, one financial

industry estimate suggests that from several to as

many as 25 nuclear power plants may retire in the

next decade and require decommissioning sooner

than expected.54Commercial nuclear decommissioning, therefore, is likely to become a more visible

and controversial political and economic issue in

the next few decades.

Although no large commercial reactors have

undergone complete decommissioning yet, decades of experience dismantling small experimental and commercial reactors, combined

with experience performing major plant upgrades and repairs at large operating units,

suggests that decommissioning large commercial nuclear power plants can be accomplished

with existing technologies. The most valuable

experience thus far has been dismantling the

72-MW Shippingport PWR, and major plant

upgrades, such as removing and replacing steam

generators, also suggests that existing technologies are sufficient to decommission large reactors.

Many of the technologies used to decommission nuclear plants are the same ones used to

demolish other industrial facilities and buildings,

including torches, saws, milling machines, and

controlled explosives. Were it not for the considerable residual radiation hazard that remains even

after the nuclear fuel is removed, a nuclear power

plant could be dismantled and demolished in the

same way as any other industrial facility or

building. Of course, the

quate decommissioning

ished if waste disposal

absent.

benefit of having adetechnologies is diminoptions are limited or

# U.S. Decommissioning Experience

Experience with decommissioning nuclear powe r

plants in the United States is limited,55 and work

is complete at only four small plant sites, the

largest being the 72-MW Shippingport PWR

(table 4-l). No large (more than 500 MW)

reactors have been decommissioned yet, and the

few reactor decommissioning performed thus far

offer little indication of the potential costs of large

reactor dismantlement, because of their low

cont amination and small size. By comparison, 96

percent of currently operating commercial reactors in the United States (103 of 107 units) are 500

53 ‘rhis ass~m w Cment rwctors operate only for the duration of their existing license terms (see table 1-2) and no units receive liu~e

renewals.

~ P.C. Parshley, D.F. Grosser, and D.A. RouleK Shearson hhman Brothers, “Should Investors Be Concerned About Rising Nuclear Plant

Decommissioning Costs?” Electric Utilities Commentary, vol. 3, No. 1, Jan. 6, 1993, p, 1,

55 A tow of 286 VtiOUS nuclear reactors (both civilian and military) have kn shut down pe rmanently in the United States. Many have been

partially or completely decommissioned, but most were generally very small (less than 10 MWe) noncommercial reactors. Thirty-seven percent

(106) of these retired units were military, productiorq and export reactors, while the greater share (180 units, or 63 percent) were civilian reactors,

including 105 test, research and university reactors (most very small general and university research reactors of less than 1 M’We); 50

experimental reactors (most for space applications); and 25 power reactors, two of which had defense applications. Thus, to date, only 23 central

station nuclear electric power units have been closed permanently, and decommissioning is complete at only 4 of them. U.S. Department of

Energy, OffIce of Scientific and ‘Rchnical Informatio~ Nuclear Reactors Built, Being Built, or Planned: 1991, DOE/OSTI-82(KM155

(Washington DC: July 1992), pp. xv, 23-27. (Note: The DOE figures are slightly revised here, in part to reflect the recent retirement of the

Yardcee Rowe, SONGS-1, and Trojan reactors.) This small subset of 23 retired units is listed in table 4-1.
Chapter 4–Decommissioning Nuclear Power Plants I 119

Table 4-l—Retired Commercial Nuclear Power Plants in the United States and

Their Decommissioning Status

Operating

Design rating license Shut down Decommissioning

Plant and type issued date approach and status

Pathfinder. . . . . . . . . . . . . . . . . . . . . .

Shippingport. . . . . . . . . . . . . . . . . . . .

Sodium Reactor Experiment. . . . . . .

Elk River. . . . . . . . . . . . . . . . . . . . . . . .

Trojan. . . . . . . . . . . . . . . . . . . . . . . . .

San Onofre Unit 1. . . . . . . . . . . . . . . .

Yankee Rowe. . . . . . . . . . . . . . . . . . . .

Rancho Seco. . . . . . . . . . . . . . . . . . . .

Shoreham. . . . . . . . . . . . . . . . . . . . . .

Fort St. Vrain. . . . . . . . . . . . . . . . . . . .

La Crosse. . . . . . . . . . . . . . . . . . . . . .

Three Mile Island Unit . . . . . . . . . . .

Dresden Unit 1. . . . . . . . . . . . . . . . . .

Humboldt Bay. . . . . . . . . . . . . . . . . . .

lndian Point Unit 1. . . . . . . . . . . . . . . .

Peach Bottom Unit 1.... . . . . . . . . . .

Fermi Unit 1. . . . . . . . . . . . . . . . . . . . .

Saxton. . . . . . . . . . . . . . . . . . . . . . . . .

Bonus . . . . . . . . . . . . . . . . . . . . . . . . . .

Carolinas-Virginia Tube Reactor. . . .

Piqua. . . . . . . . . . . . . . . . . . . . . . . . . . .

Hallam. . . . . . . . . . . . . . . . . . . . . . . . .

Vallecitos. . . . . . . . . . . . . . . . . . . . . . .

1964

1957

1957

1962

1975

1967a

1961a

1974

1989

1973

1967

1978

1959

1962

1962

1966

1963

1962

1964

1962

1962

1962

1957

1967

1982

1964

1968

1993

1992

1992

1989

1989

1989

1987

1979

1978

1976

1974

1974

1972

1972

1968

1967

1966

1964

1963

DECON completed 1991.

DECON completed 1989.

DECON completed 1983.

DECON completed 1974.

Decommissioning plan under

development.

Decommissioning planning in

progress.

Decommissioning plan under

development.

SAFSTOR until 2008; plan under

NRC review.

DECON in progress since 1992.

DECON in progress since 1992.

SAFSTOR until 2014.

Monitored storage; plant shut down

in 1979 due to reactor accident.

SAFSTOR until 2017.

SAFSTOR until 2015.

SAFSTOR until 2009.

SAFSTOR.

SAFSTOR.

DECON in progress since 1986.

ENTOMB.

SAFSTOR.

ENTOMB.

ENTOMB completed 1968.

SAFSTOR.

a Due t. a delay in the issuance of the formal operating licenses, the date of initial commercial operation is giVOn here instead.

KEY: BWR = boiling water reactor; HTG = high-temperature gas-cooled reactor; OCM = organicaoled and moderated; PTHW = pressure tube,

heavy water reactor; PWR = pressurized water reactor; SCF - sodium-oled, fast reactor; SCGM M sodiumaoled, graphite-moderated reactor.

SOURCES: U.S. Nuclear Regulatory Commission, Office of the Controller, Nuclear Regulatory Commission Information Digest: 1992 Edition,

NUREG-1350, vol. 4 (Washington, DC: March 1992), pp. 79-93; U.S. Department of Energy, Integrated Data Base for 1992: U.S. Spent Fuel and

Radioactive Waste Inventories, Projections, and Characteristics, DOWRW-0006, Rev. 8 (Washington, DC: October 1992), pp. 189-206; and the

Office of Technology Assessment 1993.

MW or larger.56 However, historical decommis- The Elk River reactor was shut down in 1968

sioning experience is telling from a technical per- after 4 years of operation.58 Dismantlement was

spective, suggesting that existing technologies are completed in 1974, after 3 years, at a cost then of

adequate to decommission today’s larger units.57 $6.15 million; this was the first commercial site

56 us, Nuclem Re@]atoV ComjSS104 (J ffjCe of tie Con@oller, ~nf~~tion Digest, ]992 Edition, NTJREG-IYS(), VOI. 4 (Washington

DC: March 1992), app. A, pp. 79-91.

57 Orgmlsation for~onomic c~opemtion~d Development Nuclear Energy Agency, Decommissioning ofNuc[ear Faci[ities:FeasibiiiV,

Needs and Costs (Paris, France: 1986), pp. 8, 31.

58 D, ~orson, ~ayment ~ue, A Reactor. by-Reactor ASsess~ent of the Nuclear Industry’s $25+ Billion Deco fnfnisSioni8 Bill (Was~ngton

DC: Public Citizen Critical Mass Energy projec~ Oct. 11, 1990), p. 14.
120 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

released for unrestricted use by the Federal

Government. 59 The Sodium Reactor Experiment

operated only from 1957 to 1964, and dismantlement was initiated in 1976.@ When decommissioning was completed in 1983, costs totaled

about $16.6 million.61 Pathfinder operated from

1965 to 1967, when it shut down due to a

condenser tube leak; dismantlement began in

1989 and was completed 2 years later.62 Although

they represent technological watersheds, these

three small commercial decommissioning projects convey little if any sense of the scale of large

reactor decommissioning work, because all were

very small, operated for brief periods, and contained far less contamination than larger, older

units that will retire in the future.

Shippingport decommissioning, however, has

received the most international attention of any

completed nuclear power plant dismantlement

project. The reactor operated from December

1957 to October 1982, and the reactor buildings

and associated nuclear portions of the facility

were completely dismantled in less than 4 years

(September 1985 to July 1989) at a total cost of

$91.3 million (nominal dollars, by year of expenditure). The turbine generator and remaining

secondary systems were not dismantled. From the

perspective of project management, the applicability of the Shippingport experience to future

large-scale decommissioning projects appears

promising-the work was completed with existing technologies on schedule and under budget.63

Doubts about the applicability of the Shippingport experience, however, center on project

costs. Unlike all of today’s large commercial

nuclear facilities, which are exclusively owned

and operated by utilities and regulated by the

NRC, Shippingport was jointly owned by the

DOE and the Duquesne Light Company (DLC);

the DOE owned the reactor and steam generating

portions of the plant, while DLC owned the

remaining facilities, such as the generating equipment and the transformer yard. In addition, as a

DOE project, Shippingport decommissioning was

not regulated by the NRC. The uncommon

ownership arrangement between the Federal Government and a private utility was designed both to

help demonstrate PWR technology and to generate salable electricity, but it also had the effect of

substantially reducing eventual decommissioning

costs.

First, as part of its demonstration effort, the

DOE replaced the reactor core twice during the

plant’s Life, each time conducting cleanup work,

including a full primary cooling system decontamination before the final core was installed.64

(Replacing reactor cores is not standard practice

for commercial nuclear power reactors.) Because

a reactor is the most heavily contaminated portio n

of a nuclear plant, the Shippingport core replacements reduced plant radioactivity substantially.

At final shut down, the last Shippingport reactor

core had been in operation only 5 years (August

1977 to October 1982), and the radioactivity in

the reactor pressure vessel (RPV) was about

59 U.S. Nucle~ Regulatory co~ssio~ office of Nuclear Regulatory Researcb Final Generic Environmental ImpaCt Statement on

Decommissioning of Nuclear Facilities, NUREG-0586 (W%shi.ngtom DC: August 1988), p. 1-5,

60 D. Borso~, Payrne~tD~e: A ReoCfor.by-ReaCforASSeS~nt of the Nuclear I~usfry’s $25+ Billion Decommissioning Bill (waSh@tOU

DC: Public Citizen Critical Mass Energy projec~ Oct. 11, 1990), p. 15.

61 j,~A. Ro~~, R+ s~w, ad K. Stikopf, “Deco~ssioning of co~erc~ Nucl~Power Plan@, ” Annual Review of Energy (ptdo

Alto, CA: Annual Reviews, Inc., 1985), vol. 10, p. 257.

62 Michel Wekr, U.S. Nuclear Regulatory Cornrnission, personal co~tiction, May b, 1993.

63 us. ConWe55, Gen@ AWoU~gOfflce,~~ippingporfDecom’ssionin@ow ApplicaNeAre the.bssonsf.earned? GAO/RCED-90208

(Gaithersburg, MD: September 1990).

~ W. Murphie, ‘Greenfield Decornrnissioning at Shippingport: Cost Management and Experience, “NuclearDecommissioning Economics:

Estimates, Regulation, Experience and Uncertainties, M.J. Pasqualetti and G.S. Rothwell (eds.), The Energy Journal, Special Issue, vol. 12,

1991, p. 121.
Chapter 4–Decommissioning Nuclear Power Plants 1121

Decommissioning of the relatively small Shippingport reactor, completed in 1989, was managed by the U.S.

Department of Energy. Although done at Shippingport, radiological decommissioning at other sites may not

require removal of buildings and other structures.

30,000 curies (Ci), which had decayed to 16,000

Ci when decommissioning began 3 years later.65

For comparison, the projected radioactivity levels

in the RPV of an 1,175-MW PWR at shut down

(assuming 30 years of effective full power operation) have been estimated at 4.8 million Ci,66

about 300 times the amount at Shippingport when

decommissioning began there.

Second, the small size and low contamination

of the Shippingport RPV allowed one-piece

disposal. Though relatively large for its low

power capacity, the Shippingport RPV was far

smaller than typical commercial units, with a

height of 25 feet, width of 10 feet, and weight of

about 153 tons. Standard-sized vessels in large

reactors, however, are 45 to 70 feet high and can

weigh as much as 1,000 tons.67 Because of their

size and expected contamination, the larger vessels at most commercial facilities are likely to

require segmentation, which will increase project

costs and radiation exposures.

As a third cost saving advantage, Shippingport

waste was delivered to Federal facilities, an

option not available to typical commercial licensees. Because the DOE managed the project, the

highly radioactive spent nuclear fuel was transported to the Idaho National Engineering Laboratory (INEL), and all LLW, including the intact

RPV, was buried at the Hanford facility in

Washington state. According to the DOE manager of the Shippingport decommissioning project, there has been no effort to determine the cost

65 U.S. Con=ess, Gen~ Accounting Office, ShippingportDecomnti,rsionin~ow Applicable Are theLessonsL.earned? GAO~mD-90208

(Gaithersburg, MD: September 1990), p. 16.

66 R.I. smith, G.J. Konze~ and W.E. Kemedy, Jr., Battelle PacKlc Northwest Laboratory, Techncdogy, Safety and Costs @ecom”ssioning

a Reference Pressun”zed Water Reactor Power Stan”on, NUREG/CR-O130, vol. 2 (Washingto% DC: U.S. Nuclear Regulatory Commission

June 1978), pp. C-10, C-12. The reference PWR used in this study is the Trojan Nuclear Plant, a recently retired commercial nuclear power

plant in Prescotg Oregon. The figure is a projection only, not an actual measured quantity at the plant.

~T U.S. Conwess, Gene~ Accounting C) free, ShippingportDecommi.rsionin@ow ApplicableAre the LessonsLearned? GAO/R~9208

(Gaithersburg, MD: September 1990), pp. 4-5. These figures reflect RPV weights prior to preparation for disposal. At ShippingporL falling the

RN witb concrete and including lifting fmtures increased the package weight to 1,100 tons. Thomas S. LaGuardi4 President, TLG

Engineering, letter to the OffIce of Technology Assessmen~ Jan. 22, 1993.
122 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

savings from the unique circumstances at the

Shippingport decommissioning.68

The reduced LLW costs, however, provide one

indication of the reduced costs experienced at

Shippingport. If Shippingport was decommissioned today and the LLW disposed at Barnwell,

the only facility available to a Pennsylvania

licensee, total project costs would be almost $56

million more, an increase of over 60 percent.69

CURRENT AND FUTURE DECOMMISSIONING

EXPERIENCE

Two recently retired plants-the 819-MW

Shoreham BWR and the 330-MW Fort St. Vrain

high-temperature gas-cooled reactor (HTGCR)--

are currently undergoing DECON decommissioning and, given their size, may provide better

indications than Shippingport of the costs, occupational exposures, and waste disposal requirements of standard-sized commercial reactors

(boxes 4-C and 4-D). More than a dozen other

U.S. civilian nuclear power units are currently

planning or undergoing decommissioning as well.

An overview of decommissioning plans for recently retired reactors is given in box 4-E.

Additional and potentially important experience with decontamination, decommissioning,

waste minimization, and radiation protection will

be gained from existing Federal nuclear remediation programs, many associated with weapons

facilities. The DOE Environmental Restoration

and Waste Management (ERWM) program covering nuclear weapons complex cleanup, the DOE

Formally Utilized Sites Remedial Action Project

(FUSRAP) covering former nuclear processing

facilities, and the NRC Site Decommissioning

Management Plan (SDMP) program for select

nuclear material sites will together provide lessons and technological improvements that the

industry may find useful as it decommissions

commercial power reactors in the future.70

The largest of these efforts, the ERWM program, is a multibillion dollar federal effort to

remediate and dispose HLW from weapons production, but the nature of this effort is different

than commercial nuclear decommissioning in

several critical respects. First, unlike commercial

nuclear waste, much defense HLW is the liquid

byproduct of reprocessing. As a result, a major

challenge in defense cleanup has been neutralizing these wastes into more stable forms, such as

salt cake, to prepare them for vitrification and

final disposal. In the commercial sector, on the

other hand, there are no plans to reprocess,

neutralize, vitrify, or otherwise transform the

solid spent fuel, the only HLW form in the nuclear

power industry, because of its existing stability.

Second, a major challenge with defense HLW

has been storing and securing the liquid material,

where tank leaks threaten local groundwater

sources and the risk of fire or explosion in some

cases is serious, in part from the accumulation of

gases generated by chemical treatment. In addition, the past mixing and treatment of defense

HLWs has raised questions about the exact

composition of many storage tanks, and sampling

@ W. Murphie, ‘Greentield Deeornmissioning at Shippingport: Cost Management and Experience, ’ Nuclear Decommissioning Econom’cs:

Estimates, Regulation, Experience and Uncertainties, M.J. Pasqualetti and G.S. Rothwell (eds,), The Energy Journal, Special Issue, vol. 12,

1991$ p. 121.

@ ‘IMS estimate is based on current (1993) Barnwell costs for out-of-region LLW generators of $270 per cubic foot. ShippiIIgpOfi LLW

totaled 214,000 cubic feet (ft3) and cost the DOE $2.2 million (year-of-expenditure dollars) for disposal at Hanford, representing just over $10

perft3. Westinghouse Hanford Co., Final Project Report: Shippingport Station Decommissioning Project, DOE/SSDP-0081 (RicMand, WA:

U.S. Department of Energy, Richiand Operations OffIce, Dec. 22, 1989), pp. ix, 10. Including only the current out-of-compact disposal

surcharge of $120 per ft3

, Shippingport decommissioning today just 4 years later would cost about $26 million more, a total increase to the

original nominal cost of about 28 percent. Applying the current Barnwell costs, however, raises the total more than 60 percent.

TO For e~ple, the DOE EnViro~enM Restoration and Waste Management program recently selected 19 R61D PrOJC.C@ tO assist with the

decontamina tion and decommissioning of closed nuclear weapons facilities, including projects designed to recycle concrete and scrap metal.

“DOE Negotiating Contracts for 19 D&D Projects Wlued at $40 MiUioQ” Weapons Complex Monitor, vol. 4, Nos. 20 & 21, Mar. 29, 1993,

pp. 7-8.
Chapter 4-Decommissioning Nuclear Power Plants ! 123

Box 4-C-The Fort St. Vrain Decommissioning Project

The Fort St. Vrain (FSV) Nuclear Generating Station was a 330-MW high-temperature, gas-cooled reactor

owned by the Public Service Co. of Colorado (PSCO). This unique reactor operated commercially from 1979 to

1989, 1 but experienced several serious difficulties, which led to low capacity and high costs. In 1986, a settlement

agreement between PSCO, the Colorado Public Utilities Commission (CPUC), the Office of the Consumer Counsel

(OCC), and other parties led to the removal of FSV from the rate base. PSCO’s subsequent decision to retire the

reactor was based on several concerns: problems with the control rod drive assemblies and the steam generator

ring headers, low plant availability (about 15 percent), and prohibitive fuel Costs.* The reactor was shut down

permanently in August 1989, and PSCO became the first commercial nuclear utility to receive a possession-only

license from the NRC since the Commission adopted decommissioning rules in 1988.

In April 1991, the Westinghouse Electric Corp. won a $100-million, fixed-price contract to perform DECON

decommissioning at FSV. Project completion is expected by April 1995, including 18 months for project planning

(previously initiated) and 39 months for decontamination and dismantlement. As of October 1992, the total

estimated decommissioning cost was $157,472,700, based on the anticipated year of project expenditures and

including escalation and utility management costs.3 Although the FSV nuclear decommissioning trust totaled only

$28 million in October 1992, the CPUC had approved a Supplemental Settlement Agreement in December 1991

allowing PSCO to recover $124.4 million, plus a 9 percent carrying cost to cover inflation, from rate payers for t he

remainder of the decommissioning work. Earlier, the CPUC had limited the rate payer liability for FSV

decommissioning to $17.5 million.

Under a Preliminary Decommissioning Plan submitted to the NRC on June 30,1989, PSCO proposed the

SAFSTOR approach. The final plan, however, was submitted November 5, 1990, and proposed the DECON

approach. In the interim, PSCO decided to convert the plant to a natural gas-fired generating station and wanted

the site available sooner. Moreover, PSCO determined that the economic advantages of SAFSTOR were less

impressive when examined in detail. For example, significant LLW volume reductions, and hence cost savings,

were not expected for 120 years. Also, PSCO did not want to remain vulnerable to Price-Anderson liability, which

is imposed on all licensed commercial nuclear reactors for accidents that occur at any U.S. facility.4 All nuclear

power licensees are subject to a potential maximum liability of $63 million in case of any major nuclear power

industry accident.5

1 The FSVOperat]ng license was issued Dec. 21,1973, andtheplant waspermanentfy closed Aug. 18,1989.

The effective operating period, however, was shorter. U.S. Nuclear Regulatory Commission, Office of the Controller,

/tiorrrration Digest, 1992 Edition, NUREG-1350, vol. 4 (Washington, DC: March 1992), p. 92.

2 FSVfuelcosts increased substantially, tonearly60 percent of the total allowed production costs of 4.8cents

per kilowatt hour (kWh) for the unit. Fuel for the next cycle would have cost the utility $80 million, or approximately

2.8 cents per kWh. At the same time, coal-fired power cost PSCO 2.7 cents per kwh and purchased power only 2.2

cents per kwh. Site Manager, Fort St. Vrain Nuclear StatIon, Public Service Co. of Colorado, personal

communication, Sept. 23, 1992.

3 Don V1/arembourg, Public Service Co. of Colorado, “Defueling & Decommissioning Considerations at Fort

St. Vrain Nuclear Generating Station,” presented at TLG Servfces, Inc., Decommissioning Conference, Captiva

Island, florida, October 1992. From Thomas S. LaGuardia, President, TLG Engineering, letter to the Office of

Technology Assessment, Jan. 22, 1993.

4 Decommissioning Project Engineer, Fort St. Vraln Nuclear Station, Public ServiCe CO. Of CdoradO, personal

communication, Sept. 23, 1992.

542 U.S.C. 2210(b)(l).

(Continued on next page)
124 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Box 4-C-The Fort St. Vrain Decommissioning Project--(Continued)

The FSV DECON project is divided into three major tasks:

1. Decontamination and dismantlement of the prestressed concrete reactor vessel (PCRV)--the major task.

2. Decontamination and dismantlement of the contaminated balance of plant (BOP) systems.

3. Site cleanup and the final radiation survey.

The total estimated occupational radiation exposure for the project is 433 person-rem: 388 person-rem for

PCRV decontamination and dismantlement, 2 person-rem for BOP decontamination and dismantlement, and 65

person-rem for waste preparation, packaging, shipping, and disposal. (For companion, the average occupational

radiation exposure at operating PWRs in the United States is 288 person-rem and at operating BWRs is 435

person-rem. 6

)

Excluding spent fuel, activation analysis suggests that the total radiation for fixed components is 594,185

curies (Ci) and 199,878 Ci for removable components for a total of 794,083 Ci. Low plant availability and the unique

HTGCR design restricted total activation and contamination (For comparison, the total radiation estimated for the

reactor vessel in the 1,175 MWe NRC reference PWR reactor after 30 years of operation is 4.8 million Ci. 7

) PSCO

estimates that the project will generate 100,072 ft3 of low-level waste (LLW), which will derive almost entirely (99

percent) from the PCRV with some contribution (about 1 percent) from the BOP. Most of the LLW is expected to

be Class A (70,788 ft3 or 71 percent) and the remainder Class B (28,293 ft3

, or 28 percent) and Class C (101 1

ft3, or 1 percent).8 The project is expected to generate no mixed wastes, and there are none onsite.

As an effort to maintain regular contact with the NRC during decommissioning, PSCO asked the agency to

retain an onsite inspector for the duration of the DECON project, as is done for operating plants.9 According to

officials working with the licensee, however, the NRC denied the request. At present, NRC decommissioning

project managers are located offsite.

Under a 1985 contract with the DOE, the Idaho National Engineering Laboratory (INEL) agreed to receive

FSV spent fuel. INELpreviously accepted three of nine spent fuel segments after refueling outages, but the State

of Idaho challenged the legality of shipping additional spent fuel to INEL. In the interim, PSCO spent approximately

$2.5 million per month to maintain the unit in its partially defueled condition in accordance with the possession-only

license. The company also hired Foster-Wheeler Energy Corp. to build a modular vault dry storage system for the

spent fuel onsite at a cost of about $23 million.

The FSV spent fuel storage facility has a 40-year design life and houses all the remaining fuel segments,

although the liners in the original shipping casks will eventually require changes to gain NRC approval for transport.

At present, these casks are certified to store, but not transport, spent fuel. In June 1992, the last of the remaining

fuel segments was placed in the modular vault dry storage facility, and the NRC approved the PSCO

decommissioning plan on November 23,1992. Active decommissioning began in January 1993.

6 me= figures reflect measured doses in 1989. C.T Raddak and D. Hagemeyer, Ocwpationa/ Radiation

Exposure at Comrm?tcial Nuolear Poww Reactors and Other Facilities: 1989, Twenty Second Annual Report,

NUREG-0713, vol. 11 (Washington, DC: US Nuclear Regulatory Commission, April 1992), p. B-3.

7 R. I. Smith, Q.J. Konze~ and W.E. Kennedy, Jr., Battelle Padfic Northwest bbOratOry, TbcfwIo/ogy, Safety

and Costs of Decwnnissioning a ReiWenoe Pressurized 144?ter Reactor Powr Station, NUREG/CR-0130, vol. 1

(Washington, DC: U.S. Nuclear Regulatory Commlsslon, June 1978), p. 7-19.

6 Anamicaj un~t~~~s s~g@thata$ much as 400 @ of the Class C LLW may require reolassifioation as

greater-than-Class C ((3TCC) waste. QTCC waste Is the only form of LLWthat is forbidden from near surface burial

and requires disposal in a geologic repository. 10 CFR 61 .55(a)(2) (iv).

g Manager, Fort St. Vrain Radiation Protection, Scientific Ecology Group, Inc., personal ~mmuni=tion,

Sept. 23, 1992.
Chapter 4-Decommissioning Nuclear Power Plants ! 125

ADDITIONAL SOURCES: A. Barrett “The Big Turnoff,” Fmanciat Wnfd, vol. 160, No. 15, July 23,1991, pp. 30-32.

“Fort St. Vrain Decommissioning Ready as Nuclear Fuel Removal is completed,” E/ectric UtMty M&ek, June 22,

1992, p. 11.

Public Service bmpany of Colorado, “Notes to consolidated Financial Statements,” 1991 Annual Report.

Public Service Company of Colorado, FVoposedDecomrn@ionhgPlan for the Forf St. V..ainiVuc/ear Generating

Station, Nov. 5, 1990.

R,R. Zuercher, “Defueled Fort St. Vrain is Ready for Decommissioning to Begin,” /Wcieonics l&e~ vol. 33, No.

26, June 25, 1992, pp. 14-15.

R.R. Zuercher, “PSC IPSCO] Gets Go Ahead to Dismantle Fort St. Vrain Gas-Cooled Reactor,” Nuckwics Wbek

vol. 33, No. 49, Dec. 3, 1992, pp. 6-7.

U.S. Nuclear Regulatory Commission, “PublicService Co. of Colorado; Issuance of Materials License SNM-2504,

Fort St. Vrain Independent Spent Fuel Storage; Installation at the Fort St. Vrain Nuclear Generating Station,” 56

Federa/ RegMer57539 (Nov. 12, 1991). I

I

1

and characterizing waste in some storage tanks # International Decommissioning

will be necessary before vitrification and dis- Experience

posal. These are not problems with commercial

spent fuel, which is not in liquid form and is not

treated or mixed with other wastes. Third, due to

HLW liquid releases (both planned and not), an

important component of the ERWM program

involves soil remediation, which is not expected

for commercial decommissioning, except perhaps

to remove very low levels of radioactivity, but

none of it HLW.71

Thus, there are several major differences between commercial nuclear power decommissioning and defense HLW remediation, but Federal

cleanup programs are likely to offer some valuable lessons about material decontamination, worker

radiation protection, waste packaging, and other

related efforts for the commercial nuclear power

sector. These lessons are likely to be imparted to

private decommissioning contractors and nuclear

utilities through the usual means, including published papers and reports, conferences and meetings, and information clearinghouses, including

those managed by the Federal Government.

Similar to the United States, international

decommissioning experience is limited to very

small reactors. Comparing the technical and

economic performance of decommissioning between the United States and other nations is

complicated by differing regulatory requirements

and waste disposal practices, as well as differences in labor costs and international exchange

rates. As a result, direct comparisons are difficult,

if not impossible.

Based on reactor generating capacity, the

largest foreign nuclear power decommissioning

projects are Gentilly-1 in Canada (250 MW),

Chinon A2 in France (250 MW), Garigliano in

Italy (160 MW), and Kernkraftwerk Niederaichbach (KKN) in Germany (100 MW). Table 4-2

lists major foreign decommissioning projects,

their status, and estimated costs. For the two

current dismantlement projects for which estimates were available (JPDR and KKN), expected

costs are greater than Shippingport--between

$120 million and $140 million (both in 1990 U.S.

71 For more tio~tion about defense HLWc]eanup, see U.S. Congress, Off Ice of ‘lkAnology Assessmen4 Lorw-LjVed Leguey: ~un@W

Hi,gh-Level und Transuranic Waste at the DOE Nuclear Weapons Complex, OTA-BP-O-83 (Wasbingto~ DC: U.S. Government Printing

Office, May 1991).
126 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Box 4-D--The Shoreham Decommissioning Project

On April 21,1989, the NRC issued the Long Island Lighting Co. (LILCO) a license under 10 CFR Part 50 to

operate the 819-MW Shoreham BWR. Two months earlier, on February 28, LILCO and the State of New York had

agreed to transfer Shoreham’s assets to the State for decommissioning. The utility pursued the full-power license

to demonstrate that the reactor was operable. The decision was costly because, by increasing plant radioactivity,

the scope and costs of decommissioning increased accordingly. LILCO estimated decommissioning costs of

$186,292,000 (1991 dollars), assuming LLW disposal costs of $240 per cubic foot. The NRC finds the estimate

conservative and acceptable.’

Shoreham operated intermittently, at Iow power, between July 1985 and June 1987. The plant was shut down

permanently on June 28, 1989, and the average fuel burnup was calculated to approximate 2 days of full-power

operation. Fuel removal was completed in August 1989, and the license was amended to possession-only on July

19, 1991.

The NRC issued the Shoreham decommissioning order June 11,1992. The order allows LIPA to perform

DECON work under the following conditions:

1. Fuel will be completely removed from the site within 6 years (all 560 fuel assemblies are currently in the

Spent Fuel Storage Pool in the Reactor Building. As of June 1990, LILCO estimated that the fuel

represents roughly 176,000 Curies).

2. Onsite LLW storage will not exceed 5 years.

3. The NRC must approve the installation of a temporary liquid radwaste system referenced in the licensee

decommissioning plan.

The total activated inventory at Shoreham is calculated to be a mere 602 Curies. iron-55 and cobalt-60

account for over 97 percent of the activity. The core shroud, top guide plate, and other RPV internals contain over

96 percent of the activated nuclide inventory. Estimated RPV dose rates for shielded workers are between 0.5 and

20 millirems per hour (mrem/hr).

LILCO estimates the entire decommissioning project will produce a total occupational exposure of about 190

person-rem. By comparison, the total occupational exposure for the Shippingport DECON decommissioning

project, a 72-MW PWR, was 155 person-rem.2 Segmenting and removing the Shoreham RPV is estimated to

account for 158 person-rem, or 83 percent of the total exposure. By comparison, the average annual exposure

at operating BWRs in the United States in 1990 was 436 person-rem.3 Even though the projected occupational

exposures at Shoreham are lower than the average annual exposures at operating BWRs, they are remarkably

high relative to Shippingport, where 16,000 curies (more than 25 times the amount of activity at Shoreham) led

to less occupational exposure. Unlike Shippingport, however, the Shoreham RPV requires segmentation prior to

disposal.

On November 22, 1991, the NRC granted LILCO an exemption from the decommissioning financial

assurance provisions under 10 CFR Part 50.75. The short life of the plant prevented the LILCO’s existing nuclear

decommissioning trust from becoming a viable funding vehicle. The exemption was granted under the following

conditions:

1 U.S. Nu~ear Regulatory Commission, Safety Eva/uatlon by the Officw of Nuclear Mater&/ *fety and

Safeguards Related to the O@rAppmving the Decommissioning Plan andAuthortzing Faoility Decommissioning

Long Island Power Authority (LIPA) Shoreham Nuclear Power Station, Unit 1, Docket No. 50-322, June 11, 1992,

p. 21. ,

2 Westinghouw Hanford Company, Elnal Project Report: f#@phgporf Statbn &xOnmkslonhg pf’o~ect

DOWSSDP-0081 (Richland, WA: U.S. Department of Energy, Riohiand Operations Office, Dee. 22, 1989), p. 13.

3 inStitU@OfN@gar Power Operations, “1990 Performance indicators for the U.S. Nuclear Utiiity indutiry”

(Atianta, GA: March 1991).
Chapter 4–Decommissioning Nuclear Power Plants I 127

1. LILCO will provide funds to an external account that would cover 3 months of the projected

decommissioning costs.

2. LILCO will maintain a $10 million external fund to ensure the facility is placed in safe storage if

decommissioning is delayed for any reason.

3. NRC will be notified at least 90 days in advance if the LILCO $300 million line of credit is cancelled or

altered.

4. LILCO will maintain an unused line of credit to cover any remaining decommissioning costs at all times.

Shoreham decommissioning will generate an estimated 79,300 cubic feet of solid radioactive waste; the

licensee has determined that the entire quantity of this waste could be stored, if necessary, in the on-site Radwaste

Building. All radioactive waste is expected to be Class A waste. No mixed waste is expected from Shoreham

decommissioning. Under current plans, the virtually unused fuel at Shoreham will be transferred to the Philadelphia

Electric Company’s Limerick nuclear power plant by February 1994. The Long Island Power Authority (LIPA), the

new operator of the plant, has agreed to pay Philadelphia Electric $45 million to receive the fuel. LIPA is currently

studying options to convert Shoreham to a fossil-fired power station.

ADDiTiONAL SOURCES: Long isiand Power Authority, Shoreharn /Vuc/ear Power Station Detwmmissioning

Han, December 1990.

U.S. Nuciear Regulatory Commission, Sa/etyEva/uation by the O/~iceo~Mm/ear Matetia/Sa~efyatiSat~uards

Related to the OrderApprovingthe Decommissioning Plan andAuthorizh?g Facility Decommissioning Long Island

Power Authority (LIPA) Shoreham Nuclear Power Station, Unit f, Docket No. 50-322, June 11, 1992.

M. Wald, “Shoreham A-Piant Has Found a Taker For its Spent Fuel,” The New York 77mes, Feb. 26, 1993, pp.

Al, B4.

R.R. Zuercher, “LiPA to Sign Cogema Contract for Shoreham Fuei Reprocessing,” iVuc/eonics 14@e~ vol. 33, No.

49, Dec. 3, 1992, p. 4,

dollars). As with the United States, however, this Decontamination Technologies

early experience may indicate little about the The contamination from the partial reactor core

future costs and other challenges of decommissioning larger units, particularly as residual radioactivity standards, occupational exposure limits,

and waste disposal options may change in the

future, both here and abroad.

B Decontamination and Decommissioning

(D&D) Technologies

A variety of technologies and approaches to

mitigate radiological contamination and to remove activation products from nuclear facilities

have been developed. The most important of

these are reviewed briefly in this section.

melt accident at Three Mile Island Unit 2 in 1979,

along with an increasing interest in reducing

worker radiation exposures at operating plants in

the 1980s, account for much of the development

of nuclear plant decontamination methods in the

last decade.72 Decontamination can lower occupational radiation exposures at nuclear plants,

lower the chances of unplanned environmental

releases, and reduce the final waste disposal

requirements when a plant is decommissioned.

Decontamination performance is expressed by

a number known as the decontamination facto r

(DF), which is simply the ratio of the measured

radiation field before decontamination to tha t

72 J.F. Remark Applied Radiolo@cal Con@o], Inc., A Review of Plant Decontamination Methods: 1988 Upahte, EpRl W-6169 (pa10 Alto,

CA: Electric Power Research Institute, January 1989), p. 1-2.
128 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Box 4-E-Financing Decommissioning for Early Reactor Retirements

2 Donald Edwards, Yankee Atomic E&ctrk ti~atkn, wdttOnm~ to the Offke of Technology

Assessment, Jan. 25, 1993.
._

Chapter 4-Decommissioning Nuclear Power Plants 129

after decontamination; a DF of 5, for example, and occupational exposures during decommisindicates that only one-fifth (20 percent) of the

radiation remains on the given plant equipment,

surface, or system and that decontamination.

removed 80 percent. The ultimate level of decontamination will depend on the process used, how

and how often it is applied, and where in the

facility it is applied. Major decontamination.

technologies and techniques used in the United

States are listed in table 4-3.

Chemical decontamination techniques represent increasingly common methods to reduce

occupational radiation exposures at operating

commercial nuclear power plants73 (see ch. 3, box

3-A), and may help reduce plant radiation levels

sioning. Electropolishing (or electrochemical

decontamination) is generally applied to excised

or segmented piping and equipment, but it can

also be used to decontaminate intact systems. The

technique works on a variety of metals and metal

alloys, allows material reuse, is relatively quick,

and produces a smooth surface (thus inhibiting

recontamination from the electrolytic solution) .74

Physical decontamination is performed with

a variety of technologies and techniques, many of

them fairly simple. For example, loose, low-level

contamination on floors, walls, and other surfaces

can be literally vacuumed or swept, while manual

scrubbing with simple cleansing compounds can

73 Ibid., p. 2-9.

74 H.D. O* GM. H~]te., WE. Kemedy, Jr., ~d G-J, Ko~ek, Battelle pacific Nofi~est h~ratory, Technology, Safery and costs of

Decommissioning a Reference Boiling Water Reactor Power Station, NUREGKR-0672, VO1.2 (Washington DC: U.S. Nuclear Regulatory

Commissio% June 1980), pp. G-1, G-3 to G-4.
130 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Table 4-2—Major International Nuclear Power Plant Decommissioning Projects

Operational Decommissioning approach,

Plant Design rating and type lifetime schedule, and estimated cost

Chinon A2 (France) 250-MW, gas-cooled, graphitemoderated reator

Garigliano (Italy)

Gentilly-1 (Canada)

160-MW, dual-cycle BWR

250-MW, heavy-water moderated,

boiling light-water cooled prototype reactor

Japan Power 45-MW BWR

Demonstration Reactor

(JPDR)

Kernkraftwerk 100-MW, heavy-water moderated,

Niederaichbach (KKN) gas-cooled reactor

(Germany)

Windscale Advanced Gas 33-MW, gas-cooled reactor

Cooled Reactor (WAGR)

(United Kingdom)

1964-85

1964-78

1970-79

1963-76

1972-74

1962-81

Stage 1 (1986 to 1992) estimated

at $39.9 million (1990 U.S. dolIars). Dormancy of at least 50

years prior to Stage 3 (dismantlement).

Stage 1 (1985 to 1995) for main

containment estimated at $54.8

million (1990 U.S. dollars). Dormancy of at least 30 years prior

to Stage 3.

Variant of Stage 1 (1984 to 1986)

estimated

Stage 3(1 986 to 1993) estimated

at $143 million (1990 U.S. dolIars). Estimate includes site restoration.

Stage 3 (1987 to 1994) estimated

at $121.4 million (1990 U.S.

dollars).

Stage 3 (1983-1998). No current

cost estimate available.

NOTE: The international decommissioning staging numbers are descriptive, and there may be some overlap between stages. In general, Stage 1

invoives placing a unit into extended storage for iater dismantlement, and activities inducfe plant and equipment sealing and extended routine

surveillance; Stage 2 involves partial decontamination and dismantlement, allowing m-use of non-radioactive plant areas; Stage 3 is final

dismantlement, where all materials and areas with radiation above regulatory ievels are decontaminated or removed.

SOURCES: Organisation for Economic Co-Operation and Development, Nuclear Energy Agency, International Co-@eration on Decommissioning:

Achievements of the NEA Co-operative Programme, 1985- ?990(Paris, France: 1992); Organisation for Economic Co-Operation and Development,

Nuclear Energy Agency, Decommissioning of Nuclear Fadlities:An Analysis of the Variability of Decommissioning Cost Estimates (Paris, France:

1991); and S. Yanagihara and M. Tanaka, “Estimating the Costs for Japan’s JPDR Project,” 7he Energy Journa/, vol. 12, Speaai Issue, 1991, p.

la.

also remove superficial contamination.75 Other

methods, including mechanical devices, are available to remove more tenacious contamination,

including high-pressure sprays (water, freon), grit

blasters, steam cleaners, strippable coatings, and

ultrasonic cleaners. Furthermore, specialized robots can be used to perform work in high radiation

or otherwise inaccessible areas.

DISMANTLEMENT TECHNOLOGIES

With the exception of specialized robots used

to perform tasks in high radiation fields or other

difficult plant areas, the technologies used to

decommission nuclear plants are generally applied in innovative ways rather than being innovative themselves. In general, the same technologies

used to dismantle other structures, such as buildIS Ibid., p. G-5.
Chapter 4–Decommissioning Nuclear Power Plants 131

Table 4-3-Major Decontamination Technologies and Techniques in the United States

Chemical decontamination

Decontamination

Technology factors (DFs)a Comments

CITROX (citric and oxalic acid) 4 to 15

CAN-DEREM (citric acid with

ethylenediamine-tetraacetic

acid, EDTA)

LOMI (low oxidation state

metal ion)

Electrochemical polishing

(electropolishing)

Strippable coatings

Water jets (high and ultrahigh pressure)

5 to 16

2 to 61

—

5 to 20

3 to 20 (high-

-pressure water jet)

Recirculating, regenerative method. Contains oxalic acid, which

may corrode some system components. Used in about 20

percent of reactor decontamination at operating U.S. units

(PWRs and BWRs).

Recirculating, regenerative method. Lacks oxalic acid and thus

safe for system components under normal conditions. Original

mixture included oxalic acid (CAN-DECON), which is still in

regular use. Generally applied to operating BWRs.

Recirculating or single-loop, non-regenerative method. Safe to

reactor components. Used in BWRs more often than PWRs.

The most widely used chemical decontamination technique

since 1985.

As with conventional methods, electropolishing may decontaminate systems in situ, eliminating the need for cutting (if

desired). Generates hydrogen, an explosive gas that must be

ventilated.

Best with less adherent contamination. May also be used to coat

surfaces prior to work. All associated waste is solid and

resulting volumes are low. Most applications require manual

removal.

High pressure water jets (up to 10,000 pounds per square inch)

work only with loose contamination; ultra-high jets (20,000 to

Robots and robotic devices Variable

60,000 psi) work well with tenacious contamination. Abrasive

grits added to better the DFs. Useful for decontaminating

inaccessible areas. High volumes of waste may be generated

and contamination may be spread if removed material is not

captured.

This is a broad category of technologies. Workable in greatly

confined work spaces, high radiation areas, and may supplement other technologies. Includes rotating water jet nozzles,

mobile concrete spallers, and other often unfunctional devices.

a Decontamination factors (DFs) MII vary greatly, dependingon the type and level of contamination, how the chemicals are applied (con~ntmtior’r,

temperature, duration, and number of flushes) and, especially, the systems or components treated (e.g., reactor water cleanup system, reactor

coolant pumps, steam generators, spent fuel pool).

SOURCES: H.D. Oak, G.M. Helter, W.E. Kennedy, Jr., and G.J. Konzek, Batelle Pacific Northwest Laboratory, Technology, Safety and Costs of

Decommissioning a Reference Boiling Water Reactor Power Station, NUREWCR-0672, vol. 2 (Washington, DC: U.S. Nuclear Regulatory

Commission, June 1980), pp. G-3 to G-5; C.J. Wood and C.N. Spalaris, Sourcebookfor Chemkal Decontamination of Nuclear Power Plants, EPRI

NP-6433 (Palo Alto, CA: Electric Power Research Institute, August 1989), pp. 1-1 to 2-1 O; J.F. Remark, Applied Radiological Control, Inc., A Review

of Plant Decontamination Methods.’ 1988 Update, EPRINP-6169 (Palo Alto, CA: Electric Power Research Institute, January 1989); and H. Ocken

and C.J. Wood, Radiation-Field Control kfanual-1991 Revision, EPRITR-1OO265 (Palo Alto, CA: Electric Power Reseamh Institute, 1992), pp. 6-1

to 6-26.
132 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

ings, bridges, and fossil-fried power plants, are

being used for maintenance and repairs at operating reactors and may be used to dismantle them as

well: plasma arc and acetylene torches, electric

saws, controlled explosives, remote cutting devices, jackhammers, and specialized robots. Major

decommissioning technologies and their functions are listed in table 4-4.

ESTIMATING COSTS AND RADIATION

EXPOSURES

Decommissioning cost estimates and radiation exposure projections developed well in

advance of reactor retirements are subject to

several major uncertainties, including the nature and extent of plant and site radioactivity at

final closure, local labor rates, waste disposal

costs, and applicable radiation standards during

dismantlement. As a result, cost estimates vary

depending on a site and its conditions, but their

reliability will tend to improve the closer a plant

is to actual decommissioning. The same is true

with projections of radiation exposures. Over the

last several years, the technical ability to estimate

the costs and radiation exposures from decommissioning has improved considerably; although

a few methodological uncertainties remain, estimates should improve with experience,

If viewed as a one time expense, decommissioning costs of several hundred million dollars

may appear large but are far less significant

compared to the life cycle costs of an operating

plant. Current estimates suggest that decommissioning costs will represent only about 1 percent

of the total generating costs over a plant’s life.76

Moreover, a doubling or tripling of current

estimates would have a minimal effect on generating costs, raising them between one and three

mills per kilowatthour.77

News stories and other reports about decommissioning projects often fail to distinguish

nominal (undiscounted) costs from real (discounted) costs, particularly those claiming de -

commissioning costs will exceed $1 billion per

reactor. 78 In real terms, current decommissioning

cost projections are in the range of several

hundred million dollars-not $1 billion or more.

As decommissioning will generally occur at least

40 to 60 years after plant construction, the future

nominal costs may appear much larger, but the

major reason is generally inflation calculated over

time. For example, real decommissioning costs

for the 1,150-MW Seabrook PWR in New Hampshire are estimated at $324 million (1991 dollars),

but the nominal costs when dismantlement is

expected to begin in 35 years are estimated at $1.6

billion (2026 dollars), which accounts for infla79 Any effort, there- tion and trust fund earnings.

fore, to compare costs for power plant projects

over time should consider the discounted value of

resources to reduce the potential for confusion.

Definitions of decommissioning that differ

from those in NRC rules, which focus only on

remediating radioactive portions of a plant,

may lead to differing expectations among State

and local governments and the public about

what the task involves and its cost. For instance,

complete plant dismantlement and site restoration

may intuitively seem like basic elements in

‘‘decommissioning’ any nuclear or non-nuclear

76 org~sation for fionomic Co-@ration and Development Nuclear Energy Agency, Decommissioning of Nuclear Facilities: An

Analysis of the Variability of Decommissioning Cost Estimates (Paris, France: 1991), pp. 7, 10,

77 A fiIl is a tit commo~y used to express electricity production costs and represents onStenth of one cent. The eStimate here ass~es

an original decommissioning estimate of $200 million and a 1,000 MWe reactor operating 25 years at a 70 percent capacity factor. Under these

circumstances, decommissioning cost increases to $400 million (doubling) or $600 million (tripling) would raise the costs of eachkilowatthour

generated over the period roughly 1.3 and 2.6 mills, respectively, assuming constant dollars.

78 See, for example, R. Johnson ~d A. De ROII.@LEW, ‘‘Closing Costs: Nuclear Utilities Face Immense Expenses In Dismantling Plants,

The Wall Street Journal, Jan. 25, 1993, pp. Al, A9.

79 R.R. Zuercher, ‘Seabrook Decommissioning Fund Case Goes ‘Ib New Hampshire High Court,” Nucleonics Week, vol. 33, No. 22, May

28, 1992, pp. 2-3.
Chapter 4–Decommissioning Nuclear Power Plants ! 133

Table 4-4—Major Decommissioning Technologies and Their Functions

Technology Application Comments (pros/cons)

Arc saw

Plasma arc torch

Oxygen burner

Thermic lance

Controlled explosives

Mechanical nibbler and shear;

hydraulic shear

Hacksaws, guillotine saws,

mechanical saws, circular

cutters, and abrasive cutters

Diamond wire saw

Concrete spaller

Abrasive water jet

Segment activated metal; segment

piping, tanks, and other metal.

Segment activated metal; segment

piping, tanks, and other metal.

Segment activated metal; segment

piping, tanks, and other metal.

Segment activated metal; segment

piping, tanks, and other metal;

cuts all types of concrete.

Segment activated metal; segment

piping, tanks, and other metal;

cuts all types of concrete.

Segment activated metal; segment

piping, tanks, and other metal.

Segment piping, tanks, and other

nonactivated metals.

Non or minimally reinforced

concrete (walls, floors).

Surface concrete removal (spalling).

Nonreinforced concrete (walls, floors).

Workable on all metals; usable in air or underwater; remote operations/needs adequate

space for blade; significant smoke generation.

Workable on all metals; usable in air or underwater; remote or portable operations/lower

thickness than arc saw; need contamination

control and standoff space behind tool.

Usable in air or underwater; remote or portable

operations/limited to carbon steel; generates radioactive fumes.

Workable on all metals; usable in air or underwater; portable operations; well-suited for

irregular surfaces/remote operations difficult; needs ventilation; requires molten metal

removal; use underwater produces bubbles,

which obscures visibility.

Workable on all metals and reinforced concrete; usable in air or underwater; remote or

portable operations/limited cutting thickness;

explosion may affect mechanical integrity

and may scatter radioactive material and

dust.

Workable on all metals; usable in air or

underwater; remote or portable operations/

usable only for thin metal pieces and pipes.

Workable on all metals; varying degrees or

portable and remote uses/slow cutting; small

to medium-thickness; space, contamination,

smoke, and other problems may apply.

Use not limited by concrete thickness/wire

requires water cooling; generates contaminated dust and water.

Thin- to medium-section spalling; allows large

structures to remain intact; no explosions

needed; minimal dust generation/difficult

with irregular surfaces and limited space.

Thin-section spalling/voluminous generation

of contaminated water.

SOURCES: Organisation for Economic Co-Operation and Development, Nuclear Energy Agency, International Co-Operation on Decommissioning:

Achievements of the NEA Co-operative Programme, 1985-1990, (Paris, France: 1992), pp. 116-1 19; and H.D. Oak, G.M. Helter, W.E. Kennedy, Jr.,

and G.J. Konzek, Batelle Pacific Northwest Laboratory, Technology, Safety and Costs of Decommissioning a Reference Boiling Water Reactor

Power Station, NUREG/CR-0672, vol. 2 (Washington, DC: U.S. Nuclear Regulatory Commission, June 1980), pp. G-1 to G-22.
134 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

facility, but these tasks are not generally necessary to eliminate the radiological hazard at a

nuclear power site. NRC rules also exclude spent

fuel removal, storage, and disposal from decommissioning funding requirements, although radiological decommissioning cannot be completed

until all fuel is removed .80 Moreover, some States

may require nonradiological dismantlement, including site restoration, suggesting that the narrow definition of decommissioning in NRC rules

excludes other potential expenses licensees may

incur or the public may expect when nuclear plant

sites are remediated.

9 Methods for Estimating Decommissioning

costs

To illustrate the relative financial magnitude of

decommissioning, some observers have compared these costs with plant construction costs.81

However, comparing decommissioning costs

with plant construction costs may be misleading. Each set of costs is partially related to reactor

size, but factors more important than size have

determined the costs for each. Key determinants

of decommissioning costs are operational history,

occupational and residual radiation standards,

and waste generation and disposal requirements—

not construction costs or much related to them.

With regard to construction costs, interest payments on loans and project delays (not reactor

size) have historically led to substantial differences; more than 60 percent of Shoreham construction costs, for example, stemmed from interest on construction loans.82 As a result, the costs

either to construct or decommission two similar

reactors may each vary greatly, depending upon

historical financial and operating circumstances.

In many cases, therefore, comparing construction

and decommissioning costs is inappropriate.

The history of construction cost estimation,

however, provides a cautionary lesson to decommissioning planners to avoid sanguine expectations that dismantling increasingly large reactors

will provide major economies of scale and

economies of learning, two assumptions that

failed to bear out with construction experience.83

COSTING METHODS

There are several basic approaches used to

estimate decommissioning costs. The least rigorous approach assumes a direct proportional relationship between decommissioning cost and unit

size for all reactors. With this approach, the ratio

of decommissioning cost to plant size (measured

by power output) for a completed project is

applied to another plant of known size to estimate

its decommissioning cost. For example, the

58-MWt (22.5-MW) Elk River BWR was DECON

decommissioned in 1974 at a cost then of $6.15

million. Applying its cost-to-size ratio (roughly

$106,000 per MWt) to a standard-sized 3,300-

MWt (1,100-MW) reactor planning DECON

suggests that the larger reactor would cost $350

go Wi~5 yms of fice~e expiration+ NRCrulesrequire commercial nuclearpowerlicensees to submit preliminary decommissioning plans,

which must indicate licensee plans to fired spent fuel management until the DOE accepts the fuel for fti disposal. 10 CFR 50.54(bb). Until

the 5-year mark however, assuming the licensee is able to plan shut down that far in advance, there are no fucial assurance requirements

to address spent fuel management storage, or disposal. The only decommissioning f~cial plarming required during the entire license term,

therefore, is for reactor dismantlement not spent fuel costs.

81 see, for example, G.R.H. Fry, ‘‘The Cost of Decommissioning U.S. Reactors: Esdmates and Experience, ’ Nuclear Decommissioning

Economics: Estimates, Regulation, Experience and Uncertainties, M.J, Pasqualetti and G.S. Rothwell (eds.), The Energy Journal, vol. 12,

Special Issue, 1991, pp. 93, 97; and D. Borson, Public Citizen Critical Mass Energy projec~ Payment Due: A Reacfor-by-Reactor Assessment

of the Nuclear Industry’s $25+ Billion Decommissioning Bill (Wash@tom DC: Public Citizem Oct. 11, 1992), p. 79.

82 ~omm s. ~G~dia, president, TLG ~@ee@, le~er to me mice of RChIIOIOgy Assessment, J~. 22, 1993.

83 R< c~tor, “Applying Construction Lessons to Decommissioning Estimates,” Nuclear Decommissioning Econom’cs: Estimates,

Regulation, Experience and Uncertainties, M.J. Pasqualetti and G.S. Rothwell (eds.), The Energy Jourrwl, vol. 12, Special Xssue, 1991, pp.

105-117,
Chapter 4–Decommissioning Nuclear Power Plants ! 135

million (1974 $) to decommission. 84 Though

conservative and unreliable, the proportional

approach provides a quick, crude estimate of the

potential cost to decommission a given plant.

To improve the crude estimates generated from

simple proportional calculations, the unit cost

factor approach was developed under the auspices

of the Atomic Industrial Forum in the 1970s to

provide a more systematic examination of likely

decommissioning costs to help set appropriate

utility rates. The approach determines unit costs

for the range of tasks (e.g., cutting and packaging

pipe of a given size) necessary to decommission

plant systems, and the unit costs are adjusted

according to assumptions about work difficulty

(expressed as quantitative “difficulty factors”)

and performance times. Total cost is the product

of the number of unit operations multiplied by

their associated unit costs. The same method is

used to determine cumulative radiation doses.

The challenge with the unit cost approach is

determining reasonable difficulty factors, which

some contend may currently be too conservative

(i.e., large) and require refinement. 85 Experience

with decommissioning one or more large commercial reactors should provide critical information about the appropriateness of current difficulty factors used in unit cost estimates. The unit

cost approach is commonly used in the private

sector, particularly by one firm (TLG Engineering, Inc. ) that has provided site-specific estimates

for more than 90 U.S. commercial nuclear power

reactors .86

Another basic approach used to estimate decommissioning costs is the detailed engineering

method. This approach is based on in-depth

reviews of specific existing operating plants to

determine labor requirements, radiation doses,

efficient work schedules, and costs. This approach was used by Battelle Pacific Northwest

Laboratory (PNL) in developing estimates for the

NRC reference reactors, which are the basis of the

Federal decommissioning financial assurance figures.

87 Both methods (unit cost factor and detailed

engineering) are used extensively today. There is

no current consensus on the more reliable approach, but both methods are likely to improve

with actual decommissioning experience at a few

large reactors, including Shoreham and Fort St.

Vrain.

There is no reliable method to project labor

costs many years in advance, because work

difficulty, worker productivity, and project scheduling will vary with time and changing conditions. Variables such as local labor rates, available labor pools, training costs, radiation exposure and monitoring requirements, technological

performance, and plant contamination levels are

generally more speculative the further a licensee

is from the commencement of decommissioning

work. With time, any of these variables could

increase or decrease final decommissioning

costs.

Current database programs, which are used in

both unit cost factor and detailed engineering

analyses, provide detailed records of plant inventories and contaminated equipment and materials;

these programs determine unit cost factors fairly

easily for simple, repetitive tasks. The challenge,

however, arises with more complicated tasks,

particularly the dismantlement of steam generators and reactor pressure vessels, The reliability of

84 RI, s~i~, ‘ ‘Generic Approaches to Estimating U.S. Decommissioning Costs, ” Nuclear Decommissioning Economics: Estimates,

Regulation, Erperienceand Uncertainties, M.J. Pasqualetti and G.S. Rothwell (eds.), The Energy Journal, vol. 12, Special Issue, 1991, p. 150.

Note: This paper uses the phrase “linear extrapolation’ to describe the proportional method of calculating decommissioning costs.

85 Ibid,, pp. 1s0-152.

86 ~oma~ ~Guardia, president, ‘IIG Engineering, Inc., comments delivered during NRC public m@ting in ~l~o~ VA, May b) l~g.

87 R,], Smith, “Generic Approaches to Estimating U.S. Decommissioning Costs,” Nuclear Decommissioning Economics: Estimates,

Regu/ufion, Experience and Uncertainties, M.J. Pa.squaletti and G.S. Rothwell (eds,), The Energy Journal, vol. 12, 1991, Special Issue, pp.

152-153.
136 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

cost estimation for this more complex work will

improve with more decommissioning experience.

Several other key uncertainties hamper current

costing models. First, scheduling and other timedependent assumptions in current models were

developed from experience with smaller dismantlement projects and may be inappropriate for

larger plants. Second, the macroeconomic supply

and demand impacts on costs are not addressed in

current models. For example, utility planners

generally assume stable unit costs for dismantlement work, disregarding the potential market

impacts of other decommissioning projects commencing in the same period.88 Third, current

models cannot reliably predict whether major

economies of scale or other benefits of experience

may occur when larger reactors are dismantled.89

In sum, future experience decommissioning

large reactors should improve cost estimation

considerably, but current uncertainties in determining the actual costs to dismantle large

(more than 50 MW) commercial reactors will

probably remain so for at least another decade,

if not longer, because no large reactors with

operational lives more than a few years have

been dismantled yet nor are likely to be soon.

Some current uncertainties with decommissioning cost estimation reflect unresolved Federal

policies and standards, including final standards

for residual radioactivity. Lingering questions

about both HLW and LLW disposal siting,

capacity, and costs also prevent plant operators

from making reliable final estimates of total

decommissioning costs. Labor and project scheduling assumptions used in current cost models

may also change with more experience dismantling larger plants, including their large components such as reactor pressure vessels. The

ultimate impact of such potential changes on total

costs remains speculative.

B Decommissioning Cost Estimates

A 1991 national survey of decommissioning

cost estimates for large operating reactors determined an average of $211 per kilowatt (kW), with

a standard deviation of $96 per kW (both in 1989

dollars). The average estimate for the 47 PWRs

surveyed was $191 per kW (standard deviation of

$65 per kW), and $248 per kW (standard deviation of $126 per kW) for the 26 BWRs surveyed.90

These figures suggest that decommissioning a

1,000-MW plant would cost about $211 million

(1989 dollars), based on existing estimates, although the standard deviation is substantial ($96

million).

These aggregate cost figures have two major

limitations. First, as discussed above, comparing

estimated costs with plant size can be misleading,

because plant size is neither the single, nor best,

measure of potential decommissioning costs.

Second, the relatively narrow range of these

estimates may reflect an artificial uniformity,

because most were derived from TLG and PNL

models.91 However, the results provide simple

averages of current decommissioning cost estimates.

88 R. cantor, “Applying Construction Lessons to Decommissioning Estimates,” Nuclear Decommissioning Economics: Estimates,

Regulation, Eqerienceand Uncertainties, M.J. Pasqualetti and G.S. Rothwell (eds.), The Energy Journal, vol. 12, Special Issue, 1991, p. 108.

89 See G.R.H. Fry, “The Cost of Decommissioning U.S. Reactors: Estimates and Experience,” Nuclear Decommissioning Economics:

Estimates, Regulation, Experience and Uncertainties, M.J. Pasqualetti and G.S. Rothwell (eds.), The Energy Journal, vol. 12, Special Issue,

1991, pp. 87-104. Exarnining the limited U.S. decommissioning experience to date, Fry argues that there appear to be few or no economies

of scale. However, the analysis includes two reactors (Fermi Unit 1 and Three Mile Island Unit 2) that experienced partial core meltdowns,

thus obscuring what may be a trend of decreasing cost with size for reactors without such major accidents. Fry concludes that more experience

will be necessary to confii whether or not scale economies will develop for large decommissioning projects.

90 P.M. Strauss and J. Kelsey, “State Regulation of Decommissioning Costs, ” Nuclear Decommissioning Econon”cs: Estimates,

Regulation, Experience and Uncertainties, M.J. Pasqualetti and G.S. Rothwell (eds.), The Energy Journal, vol. 12, Special Issue, 1991, pp.

56-64.

91 Ibid., pp. 60-63.
Chapter 4-Decommissioning Nuclear Power Plants ! 137

A series of NRC studies, using the PNL model,

has examined the potential costs to decommission

U.S. commercial reactors by examining two units

in detail. These studies are detailed engineering

analyses of the 1,175-MW Trojan Unit 1 PWR

(Prescott, Oregon) and the 1,155-MW Washington Nuclear Project (WNP) Unit 2 (Richland,

Washington) (the “reference reactors”). The

estimates vary depending on the reactor type

(PWR or BWR) and decommissioning approach.

In brief, DECON decommissioning using an

external contractor for labor and management

assistance was projected to cost $103.5 million

for the reference PWR and $131.8 million for the

reference BWR (both in 1986 dollars, assuming a

25 percent contingency) .92

The major elements of the reference PWR and

BWR cost estimates are waste shipment and

disposal, labor, and energy (figures 4-6 and

4-7). 93 For both estimates, supplies, equipment,

and other items account for the remainder of

costs. Both estimates exclude spent fuel disposal,

nonradiological decommissioning, and site restoration costs, because these activities are excluded

from the NRC definition of decommissioning.

The lack of demonstrable progress in developing a national MRS facility or a geologic repository, however, suggests that more commercial

nuclear power licensees will need to build and

operate interim spent fuel storage facilities. This

will add waste management costs of at least $20

million to $30 million per plant, representing

about 10 to 20 percent of expected dismantlement

costs. In some cases, interim spent fuel storage

will cost far more. Moreover, LLW volume

Figure 4-6--Major Costs From Decommissioning a

Reference Pressurized Water Reactor

Other

80/0

Energy ~ LLW dlsDosat

Contractor labor

21 ?40

Utility

staff labor

250/o

SOURCE: G.J. Konzek and R.1. Smith, Battelle Pacific Northwest

Laboratory, Technology, safety and Costs of Decommissioning a

Reference Pressurized Wafer Reactor Power Station: Tehnical Support for Decommksioning Matters Related to Preparation of the Final

Decommissioning Rule, NUREG/CR411 30, Addendum 4 (Washington,

DC: U.S. Nucfear Regulatory Commission, July 1988), p. 3.1.

projections from decommissioning will remain

somewhat speculative until either the NRC or the

EPA promulgates residual radioactivity standards. In addition to NRC requirements, licensee

plans or State requirements may introduce additional nonradiological decommissioning costs,

perhaps including site restoration.

The key differences between current decommissioning cost estimates generally center on the

two major cost elements—labor and waste disposal. In general, the NRC reference studies

project lower labor requirements, lower LLW

92 ~e DECON approach is a~swed for ficMpa, ~ause it is considered tie most expensive option. AS noted earlier, however,

the use of DECON (immediate dismantlement) may not be viable for many (if not most) light water reactors due to spent nuclear fuel cooling

requirements, which currently prevent fuel removal from storage pools for at least 5 years. As a result plant-specific analyses will be necessary

to determine the minimum period of safe storage prior to decommissioning. George J. Konzek Sr., Senior Research Engineer, Pacitlc Northwest

Laboratories, letter to the Office of Tkdmology Assessmen$ Jan. 8, 1993.

93 GJ, KonZk ~d RI, S~@ Batte~e Pacflc Nofiwest ~~mto~, Techno~~gy, Safeo and cos(~ of ~eco~”s~ioning a Reference

Pressurized Water Reactor Power Station: Technical Support for Decommissioning Matters Related to Preparation of the Final

Decommissioning Rule, NUREG/CR-0130, Addendum 4 (Washington DC: U.S. Nuclear Regulatory Commission, July 1988), p. 3.1; and G.J.

Konzck and R.I. Smith, Battelle Pacific Northwest Laboratory, Technology, Safety and Costs of Decommissioning a Reference Boiling Water

Reactor Power Station: Technical Support for Decommissioru”ng Matters Related to Preparation of the Final Decommissioning Rule,

NUREG/CR-0672, Addendum 3 (Washington DC: U.S. Nuclear Regulatory Commissio~ July 1988), p. 3.1.
138 [ Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Figure 4-7—Major Costs From Decommissioning a

Reference Boiling Water Reactor

Contractor labor

300/0

Other

7“/0

Sp

“!0

Iosal

Utility

staff labor

22%

SOURCE: G.J. Konzek and R.1. Smith, Batteile Paafic Northwest

Laboratory, Teehno/ogy, Safefy and Costs of Deeorntnissiont’ng a

Referenee Boiling Water Reactor Power Station: Tbchnical Support for

Decommissioning Matters Helatedto Prepwafion of the final Drwarnrnissioning Ru/e, NUREGfCR-0672, Addendum 3 (Washington, DC:

U.S. Nuclear Regulatory Commission, July 1988), p. 3.1.

volumes, and hence lower costs than most sitespecific industry estimates.94 For example, an

independent industry analysis of the NRC reference BWR estimates that DECON decommissioning (using the NRC definition) will cost

$201.5 million (1987 dollars), about 46 percent

more than the $138 million (1987 dollars) projected in the PNL study. While the industry

analysis estimated LLW generation of 24,489 m3

,

a 29 percent increase over the NRC figure, this

difference accounted for a minor portion of the

cost difference. Instead, the most significant

difference between the estimates, about $40

million, was labor costs.95 Field experience from

future dismantlement projects will eventually

help test the reliability of the methods underlying

these estimates.

Under contract with the NRC, PNL is revising

both reference reactor cost estimates. Although

no report has been finalized, the revised PWR cost

estimate is currently $124.6 million (1993 dollars), about $5 million less when adjusted to the

original (1986) dollars. The report authors attribute the cost decrease to LLW volume reductions

but also acknowledge many of the excluded costs

(e.g., spent fuel management) and other uncertainties (e.g., absence of residual radioactivity

standards, LLW disposal costs). This estimate

could more than double when the excluded costs

and the other uncertainties are considered.96

1 The Impacts of Life Extension on

Decommissioning Costs

The impacts of license renewal on decommissioning are a likely deferral of dismantlement

work, a slight increase in final plant radioactivity

levels, and the disposal of any major equipment

replaced during the renewal term (e.g., PWR

steam generators, BWR turbine blades). A 1991

PNL study estimated the impacts on decommissioning costs of extending operations of the

reference reactors by 20 years and assumed that

some major equipment (RPV and internals)

would need replacement. 97 Even under this unlikely scenario of RPV replacement, the estimates

94 P.M. Strauss and J. Kelsey, “State Regulation of Decommissioning Costs,” Nuclear Decom”ssioning Economics: Estimates,

Regulation, Experience and Uncertainties, M.J. Pasqualetti and G.S. Rothwell (eds,), The Energy Journal, vol. 12, Special Issue, 1991, pp.

60-63.

95 G+j. K~uek~d RI, Smi@ Ba~el]e Pacific No@westLa~ratory, Tecfino/ogy, Safety and CoStS ofl)ecornrnissioning aRtgferenceBoiling

Water Reactor Power Station: Comparison of Two Decommissioning Cost Estimates Developed for the Same Commercial Nuclear Reactor

Power Station, NUREG/CR-0672, Addendum 4 (WashingtorL DC: U.S. Nuclear Regulatory Commissio~ December 1990), pp. 2.5,

2.10.

96 E. me, ‘‘pNL Study Cuts Cost Estimate For Nuclear Dtxommis sioning,” The Energy Daily, vol. 21, No. 123, June 29, 1993, p. 3.

97 R.1, Smith, Battelle Pacific Northwest Laborato~, “Potentiat Impacts of Extended Operating License Periods on Reactor

Decommissioning Costs, PNL-7574 (Richkmd, WA: Battelle Pacitlc Northwest Laboratory, March 1991). All material in this section is from

the PNL report.
Chapter 4–Decommissioning Nuclear Power Plants ! 139

indicated that extended operations would minimally affect final decommissioning costs, adding

about $2 million (1986 dollars) to dismantle each

reactor. However, the analysis was limited to

GTCC disposal costs and assumed that replacing

the RPV and internals during the extended license

term would account for the major increase in

decommissioning costs (aside from PWR steam

generator replacement). The study estimated that

most of the estimated cost increase could be

eliminated by high-density packaging of the

GTCC waste, a procedure not considered in the

original PNL reference reactor analyses.

In the original reference PWR and BWR

analyses, LLW disposal represented the largest

single cost. On the basis of uncertainty, however,

the life extension study did not estimate future

LLW disposal costs but indicated that new

compact sites could charge as much as $100 to

$200 per cubic foot (excluding surcharges) by the

year 2000. A key determinant of potential future

costs, therefore, was excluded. The impacts of

other uncertainties (e.g., labor cost escalation and

future residual radioactivity standards) were not

examined.

B Estimating Radiation Exposures for

Decommissioning

The human health and environmental challenge during decommissioning is to hold radiation exposures as low as possible. This section

reviews the results of modelling estimates of

collective radiation doses from decommissioning. In addition, the section summarizes predicted

or measured doses from several actual steam

generator replacement and reactor decommissioning projects. Radiation standards during decommissioning (10 CFR Part 20) are the same

that apply during plant operations (see ch. 2).

Although the NRC does not set collective dose

standards, the measurement is used to compare

the aggregate exposures for different tasks (e.g.,

decommissioning) conducted at nuclear facilities. 98

COLLECTIVE DECOMMISSIONING DOSE:

PROJECTIONS BASED ON THE NRC REFERENCE

REACTORS

The collective doses projected for decommissioning the two NRC reference reactors are given

in figures 4-8 and 4-9. The values differ significantly, depending on the reactor type (greater

collective dose for BWRs generally), decommissioning approach (greatest collective dose

for DECON), and the length of time work is

deferred (lowest collective dose for 100-year

SAFSTOR).

In brief, BWRs are single-loop systems that

channel reactor cooling water in the form of steam

directly to the turbines, leading to greater contaminant dispersion and thus explaining the higher

projected doses for decommissioning. For the

same reason, BWRs also produce greater collective doses than PWRs during normal operations.

In addition, more plant radioactivity decays the

longer decommissioning is deferred, explaining

why 100-year SAFSTOR produces the lowest

collective doses and DECON the highest. (This

study projected that ENTOMB yielded greater

collective doses than SAFSTOR, because the

former method was assumed to involve more

decontamination and some partial dismantlement

earlier than the SAFSTOR scenarios.)

The NRC projections suggest that the annual

collective occupational doses associated with

decommissioning are very similar to those experienced while plants are in operation, even in the

worst dose scenario (four-year DECON). The

DECON estimates represent an annual average

PWR dose of about 279 person-remand an annual

average BWR dose of about 440 person-rem. By

comparison, the average annual occupational

98 me ~jor l~i~tion ~1~ ~ollective exposue num~rs is tit hey me averages; me v~ation in hdivid~ exposures, no matter ho w

significant, is not indicated by this number, and individual or collective radiation risks cannot be determined by this number either. It is merely

a gross measure of the average individual exposure in an affected group,
140 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Figure 4-8-Collective Radiation Doses From

Decommissioning a Reference Pressurized

Water Reactor

1,400

1,200

1,000

~ 800

&

3

~ 600

400

200

0

1215

U Occupational dose

_ Public dose

1021

DECO N 1O-yr 30-yr 100-yr ENTOMB ENTOM B

SAFSTO R internals internals

in out

SOURCE: U.S. Nuclear Regulatory Commission, Office of Nuclear

Regulatory Research, Final Generic Environmental Impact Statement

on Decommissioning of Nuclear Facilities, NUREG-0586 (Washington,

DC: August 1988), pp. 4-8.

dose at operating PWRs in the United States in

1990 was 294 person-rem and 436 person-rem at

operating BWRS.

99

Collective public dose from decommissioning

is minimal compared to collective occupational

dose. Under all scenarios, for both PWRs and

BWRs, collective public dose derives almost

entirely from the truck shipments of radioactive

waste to the disposal facilities. Projections of

collective occupational doses, on the other hand,

for DECON and 10-year SAFSTOR are principally from decontamination activities, while most

occupational doses for 30- and 100-year SAFSTOR stem from activities associated with storage preparations.100

COLLECTIVE DOSE: OTHER PROJECTIONS AND

RELATED EXPERIENCE

Limited but useful information from actual

decommissioning and nuclear plant maintenance

projects suggests the relative radiological impacts

expected from future decommissioning work.

The Shippingport decommissioning project, for

example, disposed of 16,000 Ci and resulted in a

collective occupational exposure of 155 personrem, only 15 percent of the 1,007 person-rem

projected during decommissioning planning. Shippingport decommissioning project management

attributes the lower occupational dose to ALARA

(as low as reasonably achievable) planning and

coordination. However, by not segmenting the

RPV, which contained over 99 percent of the

disposed curies, project planners unquestionably

eliminated much of the expected occupational

dose at Shippingport.lO1

Unless other technologies or techniques such

as metal melting are applied in the future, RPV

segmentation is likely to be the norm for most

commercial nuclear power plant decommissioning work, and this will increase decommissioning

exposures considerably relative to Shippingport.

At both Fort St. Vrain (box 4-C) and Shoreham

(box 4-D), RPV dismantlement is expected to

account for most of the occupational exposures

but, like Shippingport, the radiation at these units

was almost entirely present in their RPVs; this

will not be the case with larger units that operate

longer.

99 Institute of Nuclear Power Operations, “1990 Performance Indicators for the U.S. NuclcarUtility Industry’ (Atlanta, GA: March 1991).

lm U.S. NUCIW Re@ato~ Co&ssion, Office of Nuclear Re@atory Research Final Generic Environmental Impact Statement on

llecommissioning of Nuclear Facilities, NUREG-0586 (Washington DC: August 1988), pp. 4-8,5-8.

101 RpV se~entation was pti of the Ofi@ S~PP@Pfi‘eco mmissioni.ngplan. Westinghouse Hanford Company, FinalProjectReport:

Shippingport Station Decommissioning Project, DOE/SSDP-00t31 (Richland, WA: U.S. Department of Energy, Richland Operations Office,

Dec. 22, 1989), pp. 13,48.
.

Chapter 4-Decommissioning Nuclear Power Plants I 141

Figure 4-9—Collective Radiation Doses

From Decommissioning a Reference Boiling

Table 4-5-Occupational Radiation Exposures

From Recent Steam Generator Replacements

2,500 ~-

Water Reactor

D Occupational dose

0

m Public dose

1672

1543 n

DECO N 10-yr 30-yr 100-yr ENTOMB ENTOMB

SAFSTOR internals Internals

in cut

SOURCE: U.S. Nuclear Regulatory Commission, Office of Nuclear

Regulatory Research, final Generic Environmental Impact Statement

on Decommissioning of Nuclear Facilities, NUREG-0586 (Washington,

DC: August 1988), pp. $8.

Collective occupational radiation exposures

measured from recent steam generator replacements at U.S. operating plants have been as high

or higher than the NRC projections of average

annual DECON exposures (table 4-5). As these

figures suggest, exposures from major maintenance activities at operating commercial plants

are comparable to expected decommissioning

exposures and therefore represent common, generally accepted levels of risk.

REACTOR RETIREMENT AND FINANCIAL

REQUIREMENTS

Beyond estimating decommissioning costs, a

challenge remains to collect reasonable decommissioning funds while a unit is still operating,

rather than later when electricity production has

ceased. In cases of early reactor retirement,

decommissioning funding shortfalls may be sigNet capacity

Unit (year of replacement) (MWe)

H.B. Robinson 2 (1984 ).. . . . . 739

Cook 2 (1988) . . . . . . . . . . . . . . 1,133

Indian Point 3 (1989). . . . . . . . 1,013

Palisades (1990). . . . . . . . . . . 805

Millstone 2 (1993 ).... . . . . . . . 889

North Anna 1 (1993 ).... . . . . 947

Total exposure

(person-rem)

1,207

561

540

487

650

240

SOURCES: North Anna data from R.R. Zuercher, “Virginia Power Sets

World Record For Steam Generator Replacement,” Nudeonics Week,

vol. 34, No. 15, Apr. 15, 1993, pp. 1, 11; Millstone data from R.R.

Zuercher, “NU Restarts Millstone-2 Following Extended Steam Generator Outage,” Nucleonics Week, vol. 34, No. 3, Jan. 21, 1993, pp. 6-7;

all other data from H. Hennicke, ‘The Steam Generator Replacement

Comes of Age,” Nuclear Engineering International, vol. 36, No. 444,

July 1991, p. 23.

nificant (box 4-E), although the costs of unrecovered plant capital will often match or exceed the

remaining decommissioning liability (see ch. 3)

and thus introduce larger impacts on consumer

electricity rates than decommissioning shortfalls.

This section reviews the major regulatory issues

relating to decommissioning and its financing,

including relevant NRC requirements, funding

options, and the performance of existing funds.

Although the NRC has established minimum

funding levels to plan for decommissioning, Stat e

utility commissions have the major role in determining the actual timing, amounts, and other

conditions of decommissioning financing.

None of the three general decommissioning

approaches (DECON, SAFSTOR, or ENTOMB)

is the obvious choice for most decommissioning

work, and NRC rules do not dictate which option

to use. The approach chosen by licensees will

depend on site-specific conditions, including the

availability and costs of LLW disposal facilities,

the economic potential and regulatory requirements for later site use, and the particular need or

urgency (if any) to eliminate the potential environmental and financial liability that a contaminated site represents. For purposes of financial

planning, most commercial nuclear power licen-
142 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

sees assume they will DECON decommission,102

but recent data suggest that DECON may not be

viable for many light water reactors.103 A n d

although numerous small research reactors have

undergone ENTOMB decommissioning, the NRC

considers its technical viability for large commercial plants limited.104 As a result, under current

regulations and technical specifications, most

U.S. commercial power reactors are likely to

complete decommissioning within a period ranging from 5 to 60 years after they retire.

M Terminating an Operating License

Under NRC rules, commercial nuclear power

licensees must apply for the termination of their

operating licenses within 2 years after permanent

shutdown and in no case later than 1 year before

license expiration, If not submitted earlier, a proposed decommissioning plan must accompany an

application for license termination. Proposed

plans must describe the decommissioning approach, procedures to protect occupational and

public health and safety, and an updated cost

estimate.105 A license may not be terminated until

the site is remediated and a final radiation survey

performed.

A variety of safety requirements that apply to

operating reactors become unnecessary once operations cease permanently. In recognition of that,

NRC Regulatory Guide 1.86 allows plant operators to apply for an amended operating license

that allows plant possession only. A ‘‘possessiononly license” (POL) exempts plant operators

from a variety of costly operating requirements,

including requirements applied to emergency

core cooling systems (10 CFR 50.46), in-service

inspection (10 CFR 50.55a(g)), and reactor fracture toughness against pressurized thermal shock

(10 CFR 60.61).106

With an approved POL, licensees may forego

NRC annual operating fees, which amount to

roughly $3 million per unit.107 The saved resources may be used for other work, such as

decommissioning planning and execution, but

there are no current standards and guidelines that

specify the format of POL applications. As a

result, such applications are developed on a

case-by-case basis.108By issuing standards and .

guidance clarifying the role of and application

process for POL status, the NRC would help

ensure that post-closure licensee activities and

costs are reasonably minimized and that final

1~ P.M. Strauss and J. Kelsey, “State Regulation of Decommissioning Costs, ” Nuclear Decommissioning Economics: Estimates,

Regulah”on, Experience and Uncertainties, M.J. Pasqualetti and G.S. Rothwell (eds.), The Energy Journal, vol. 12, Special Issue, 1991, pp.

56-65. Of course, deferring plant dismantlement (the SAFSTOR approach) would reduce significantly the amount of LLW necessary for

disposal, but there are other costs (license fees, security, taxes, insurance) and uncertainties (potential changes to waste disposal capacity,

disposat costs, or regulatory release criteria) associated with deferring dismantlement.

103 The use of DECON (~ediate dis~tlement) my not be viable for IIMUy (if not most) fight water reactors due to spent nuclear fuel

cooling requirements, which currently prevent fuel removal from storage pools for at least 5 years. As a resul~ plant-specific analyses will be

necessary to determine the minimum period of safe storage prior to decommissioning. George J. Konze~ Sr., Senior Research Engineer, Pacitlc

Northwest Laboratories, letter to the Office of Twhnology Assessment Jan. 8, 1993.

1~ U.S. NucI@ Re@atory Commission, Hlce of Nuclear Regulatory Researe~ Final Generic Environmental Impact Statement on

Decommissioning of Nuclear Facilities, NUREG-0586 (Washingto~ DC: August 1988), pp. 2-6 to 2-12. For large reactors with long

operational lives, the ENTOMB approach is not likely to ensure sufficient decay of long-lived radioisotopes within reasonable periods (e.g.,

100 years) to allow site release.

10510 cm 50,82$

106 Nucl~ -gement ad Reso~ces Comcfi, ~c,, Regulato~ process for Decommissioning Prematurely Shutdown ?’[ants, NUMARC

92-02 (Washington, DC: November 1992), p. 4-4.

10710 cm 171.15.

108 NUCIW M~gement ~d Reso~ces council, ~c., Reguiatoq ProceSSfor Deco~”SSioning l’re~mre[y shutdown P[ants, NUMARC

92-02 (Washington, DC: November 1992), p. 4-1.
decommissioning planning and execution could

begin as expeditiously and safely as possible.

H NRC Financial Assurance Requirements

NRC financial assurance rules are designed to

ensure that sufficient funds are available to

decommission nuclear plants even if the licensee

defaults. 109 Although the default of an electric

utility is rare, decommissioning financial assurance is considered necessary, because electric

utilities are typically private, investor-owned

firms that are vulnerable, as any other firm, to

insolvency. In addition, if the salvage value of a

power plant exceeded its expected cleanup costs,

the need for financial assurance requirements

would be less compelling, but potential salvaging

revenues for nuclear plants are limited (perhaps a

few tens of millions of dollars at best) relative to

decommissioning costs (a few to many hundreds

of millions of dollars).

Under NRC rules, the minimum financial

assurance that licensees must provide to decommission each of their reactors is determined by a

sliding scale that considers primarily the type and

size (as measured in MWt) of a reactor.110 In 1986

dollars, the minimum financial assurance for

decommissioning a PWR ranges from roughly

$86 million for the smallest reactors to $105

million for the largest, and the minimum financial

assurance for a BWR ranges from roughly $115

million to $135 million.l11 These regulations

contain additional requirements to adjust annually the escalations in labor, energy, and LLW

burial costs112 (the most significant components

of decommissioning expenses). Utilities are required to perform but not report these adjustments.

Chapter 4-Decommissioning Nuclear Power Plants I 143

H Adequacy of NRC Financial Assurance

Requirements

The NRC maintains that the amounts in the

financial assurance rule are not decommissioning

cost estimates but rather provide a reasonable

approximation of the minimum costs of decommissioning. In the Supplementary Information to

its 1988 decommissioning rule, the NRC suggested that the financial assurance provisions

should provide the bulk (not necessarily all) of the

funds needed to decommission commercial nuclear plants in the United States.113 In that respect,

though, the amounts represent an actual (though

perhaps minimum) estimate.

The NRC financial assurance rules establish

finding levels for commercial power plants in

each reactor class (PWR or BWR) by adjusting

primarily for size. While these rules are based on

detailed engineering studies of two reference

reactors, the generic approach may not be satisfactory for providing reliable financial assurance

for the entire industry given the significant

differences in individual reactor designs, operating histories, eventual plant contamination, and

other factors that will be more important than size

in determining final decommissioning costs at

many (if not most) commercial nuclear power

plants in the United States.

A simple understanding of plant size may not

be sufficient to predict or plan financially for total

project costs, if plant design, final contamination,

and other site conditions have more important

impacts on decommissioning costs than reactor

size. Compared to site-specific decommissioning

estimates performed for several recently retired

reactors (box 4-E), the NRC requirements are

consistently and substantially low.

I@ 53 Federal Register 24018-24056 (June 27, 1988).

110 me capacl~ of ~ el~rncal generating plant can be expressed in MWe (eleetrieal capacity) or MWt (thermal capacity). ne NRC

decommissioning fmcial assurance requirements are based on MWt, which is considered a better indication of physical plant size. MWe,

on the other hand, is a measure of the efficiency of power conversion which can change over time without any changes to plant size.

I 11 10 CF’R 50,75(C)(1).

1 IZ 10 cm 50.75(c)(2).

11353 Federal Register 24030 (June 27, 1988).
144 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Furthermore, the current regulatory definition

of decommissioning and the related NRC financial assurance rules under 10 CFR 50.75 exclude

spent fuel disposal, its associated costs, and other

potential nonradiological expenses (e.g., site

restoration) that States may require. As plant

decommissioning cannot be completed before all

spent fuel is removed, the current regulatory

distinction between spent fuel waste disposal and

other decommissioning activities is arbitrary and

masks the range of activities and costs needed to

complete “decommissioning,” even as defined

by NRC rules. As previously discussed, the costs

of providing any needed interim storage for spent

fuel can be substantial, about $20 million to $30

million per plant, which is in the range of 10 to 20

percent of the current estimates of radiological

decommissioning.

Post-closure costs such as plant maintenance

and inspection, security, property taxes, insurance, and remaining license fees may be significant as well but are also excluded from NRC

decommissioning financial assurance requirements, which focus on removing site radiological

contamination. As a result, radiological decommissioning is only one part (although perhaps the

most important) of post-closure expenses at

commercial nuclear power plants, but future

changes to NRC financial assurance rules could

include some of these other costs, such as spent

fuel management, plant maintenance and monitoring, insurance, and site security.

There appears to be widespread agreement

among utilities, State public utility commissions (PUCs), and even the NRC that the

reference reactor decommissioning cost estimates underlying the NRC financial assurance

rules are low. The NRC is currently updating its

studies of the reference reactors, one of which

(Trojan) retired this January. In the meantime,

utilities and PUCs have relied increasingly on

site-specific cost estimates to prepare for eventual

decommissioning; most licensees, in fact, now

use site-specific estimates. Thus, the future benefit of revising the generic NRC financial assurance formulae may be negligible. Encouraging

licensees to develop and update regularly their

own site-specific decommissioning cost estimates may have more value in assuring adequate

financing than actually revising the regulatory

figures in 10 CFR 50.75.

NRC rules require licensees to submit a preliminary decommissioning plan and cost estimate

about 5 years prior to expected plant retirement.114 However, the licensees of all seven

reactors that retired early in the last 14 years had

far less than five years to plan for their respective

reactor retirements, suggesting that this generic

requirement may also have little practical value in

assuring adequate decommissioning financing.

EARLY REACTOR RETIREMENT

The recent trend of early nuclear power plant

retirements undermines the basic NRC objective

that licensees have available sufficient decommissioning funds at final shutdown, an objective

expressed as part of the 1988 rule.115 With early

retirement, the operating period assumed for the

collection of decommissioning funds is reduced,

often substantially. Collections for decommissioning trusts are calculated assuming a unit

operates its full licensed life. The average life,

however, of the seven retired reactors was less

than 15 years. Excluding arguable anomalies such

as Three Mile Island and Shoreham, both of

which shut down after a year or less of operations,

the average life of the remaining five plants was

only 20 years, half the time assumed in standard

license periods. These early retirements highlight

11410 Cm 50.75(i3. ‘rhis rule does not speciilcally require a site-specific eSt@3te.

11553 Federal Regisrer 24031 (June 27, 1988).
Chapter 4-Decommissioning Nuclear Power Plants ! 145

the need to re-examine the NRC financial assurance requirements to ensure that adequate decommissioning resources are available (or assured)

whenever a plant closes. Also, as discussed in

chapter 3, the allocation of decommissioning

costs among current and future consumers and

utility shareholders is an issue for which there is

limited precedence.

FUNDING REQUIREMENTS FOR EARLY REACTOR

RETIREMENT

In 1992, the NRC promulgated a rule to address

decommissioning funding for reactors retired

prior to their license expiration. Recognizing that

licensees generally have access to significant

financial capital, the NRC decided to determine

the need for accelerated fired accumulation based

on case-by-case determinations of licensee financial conditions.116

These requirements are based on two basic

principles stated in the preamble to the rule. One,

all decommissioning funds should be collected

before the original operating license term expires.

Two, licensees may collect funds during any

storage period, but only until the license expiration date and only if they maintain a bond rating

of at least “A” or equivalent by Moody’s

Investment Services, Standards and Poors, or

another national rating agency. If licensee bond

ratings fall below the “A” screening criterion

more than once in a 5-year period, the balance of

decommissioning funds may have to be collected

and deposited into an external account within 1

year of the downrating, unless other criteria that

reasonably assure financial solvency are met.117

There are several potential problems with the

decommissioning financial assurance rules as

applied in cases of early retirement. First, linking

bond rating to fund accumulation may effectively

eliminate SAFSTOR as a financially attractive

decommissioning alternative by potentially limiting the period in which funds may be collected.

Second, the rule may create a disincentive to close

uneconomic plants out of concern to collect

sufficient decommissioning funds during operations. Third, requiring licensees to collect the

remainder of any funding shortfall precisely when

their bond ratings drop may aggravate further

their financial position, without substantially

improving the prospects of collecting all decommissioning finds. Finally, these rules may assure

adequate funding for eventual decommissioning,

but they do not prevent future ratepayers from

paying the bulk of decommissioning costs.

POST-ACCIDENT PREMATURE

DECOMMISSIONING INSURANCE

In 1991, insurance became available to cover

the costs of premature decommissioning from

severe accidents that cause property claims to

exceed $500 million. Both of the two nuclear

excess property insurers provide coverage. Nuclear Electric Insurance Limited (NEIL), an

industry-sponsored organization, will cover the

difference between the amount in the decommissioning trust fund and final target up to the

pre-selected sublimit. (The current maximum is

$200 million, which is expected to increase to

$250 million.) American Nuclear Insurers and

Mutual Atomic Energy Liability Underwriters

(ANI/MAELU), pools of commercial insurers,

will indemnify decommissioning coststoa‘‘greenfield” condition, once other decommissioning

funds are exhausted, up to $100 million.118

FUNDING REQUIREMENTS IN OTHER NATIONS

Official decommissioning funding requirements

in other nations vary considerably, and many are

11657 Federal Register 30383-30387 (July 9, 1992). S* 10 Cm 50.82(a).

117 ~e~e ~~er ~-ite.ia fi~lude ~ ~v~mtion of tie licm~e’s ~cial ~stoly, loc~ ad Smte regulatory conditio~, the number of its Other

nuclear and non-nuclear generating plants, and other factors deemed relevant by the NRC. 57 Federal Register 30385 (July 9, 1992).

118 ABZ, IIIC., $ ‘Case s~dies of Nine Operating NuclearPower Plants: Life Attainrn en~ License Renewal and Decommissioning, contractor

report prepared for the Office of Tkcbnology Assessment February 1993, p. 52.
146 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

far less rigorous than NRC requirements. The

governments of Germany, Italy, and the United

Kingdom have not imposed decommissioning

funding requirements, although German plant

operators make voluntary financing arrangements.

The Canadian government requires nuclear operators to arrange decommissioning financing but

does not specify actual amounts or funding

methods. Finland, Spain, and Sweden have decommissioning funding requirements but, unlike

the United States, monies are collected from

operators by their respective governments and

managed in separate national finds. In France, the

government-owned utility adjusts its accounts

monthly to help finance future decommissioning

based on the product of reactor capacity (size)

multiplied by 15 percent of the construction costs

of a reference 1,300-MW PWR. In Japan, where

85 percent of collected fund monies are tax-free,

utilities determine decommissioning funds based

on the estimated weight of dismantled plant

wastes. 119

1 Funding Options

By July 1990, NRC licensees were required to

submit reports indicating their plans to provide

reasonable financial assurance for decommissioning.120 These reports had to specify the type

and amount of financial assurance provided,

using either site-specific cost estimates or the

NRC regulatory minimum given in 10 CFR

50.75(c). Three general types of financial assurance are eligible: prepayment; an external sinking

fund; or a surety method, insurance, or other

guarantee.

Prepayment, as the word suggests, involves

depositing sufficient cash or other liquid assets

prior to facility operations into an account maintained separately from licensee assets to fund

decommissioning. Prepayment may be in the

form of a trust, escrow account, government fund,

certificate of deposit, or deposit of government

securities. 121 An external sinking fund is also

maintained separately from licensee assets, but

payments are made at least annually during

operations rather than in advance. External fund

investments may be the same as those for

prepayment. 122 The last decommissioning option—

a surety method, insurance, or other guarantee

method-may be in the form of a surety bond, a

letter of credit, or a line of credit, but any surety

method used must remain effective until the NRC

terminates the license. 123 Most licensees use an

external fund to finance decommissioning.124 The

choice is understandable: prepayment is expensive, requiring a licensee to collect all decommissioning monies in advance and, until recently, no

decommissioning surety options were available

on the market.

QUALIFIED AND NONQUALIFIED EXTERNAL FUNDS

Before 1984, any funds collected for decommissioning were federally taxed. By 1986, statutory changes allowed Federal tax deductions for

1 w org~sation for ~onomic Co-OWration and Development, Nuclear Energy Agency, Decommissioning of Nuclear Facilities: An

Analysis of the Variability of Decommissioning Cost Estimates (Paris, France: 1991), pp. 104-108.

12010 cm 50.33(k),

121 10 CFR 50.75(e)(l)(i).

12210 CFR 50.75 (e)(l) (ii), (c)(3)(@.

in 10 cms. 75(e) (1)(iti), (e)(l) (hi)(C) Unti 1990, many ficens~s titied internal demtissio~ acco~ts to con~ol be*ter *eh

financial managemen~ but concerns about the loss of these funds in cases of utility insolvency led the NRC to eliminate this option. 53 Federal

Register 24033 (June 27, 1988).

lx “Outlook On Decommissioning Costs,” Nucleonics Week, Sept. 27, 1990, Special Repoz p. 5. This review examined documents filed

for 68 nuclear plants.
Chapter 4-Decommissioning Nuclear Power Plants 147

any decommissioning funds placed in qualified

investments (public debt securities and bank

deposits). Decommissioning funds may be invested in other securities, but they are ineligible

(nonqualified) for corporate tax deductions and,

until recently, faced the full corporate tax rate of

34 percent. Nonqualified funds, such as mutual

funds, are higher risk investments that generally

earn more than qualified funds-even accounting

for their greater tax burden. Nonetheless, most

decommissioning monies are invested in qualified funds.125

In recent years, many investment managers and

utility analysts have argued that earnings from

many qualified investments, though relatively

safe financially, have not performed well, some

barely (if at all) earning more than inflation.126

Although monies placed in qualified funds have

been tax deductible, their earnings were taxed at

the full corporate rate of 34 percent. Moreover,

disbursements from qualified funds were taxed at

the full corporate rate, reducing substantially the

benefits of their qualified status. At the same time,

even though nonqualified fund monies were

taxed, their disbursements were not, increasing

substantially their stature as an investment option. Concerns about trust fund earnings recently

prompted Congress to repeal the investment

restrictions on qualified external funds and reduce

their applicable tax rates to 22 percent in 1994 and

20 percent starting in 1996.127 At present, nuclear

decommissioning trusts (NDTs) total an estimated $5 billion to $7 billion, with an estimated

80 percent invested in municipal bonds. The

recent congressional changes, however, are likely

to shift many investments to other, higher yielding securities.128

B Performance of Existing Funds

In 1990, the Critical Mass Energy Project of the

nongovernmental group Public Citizen surveyed

the status of existing NDTs. Their findings

suggest that commercial nuclear power licensees

are not collecting decommissioning funds quickly

enough. The group determined that less than 14

percent of the total sum of all projected U.S.

nuclear power plant decommissioning costs had

been collected, even though more than 33 percent

of their expected operational lives had passed

(assuming neither life extension nor premature

retirement). 129 However, with compounded interest earnings, net NDT growth will accelerate in

later years. In addition, the NRC financial assurance rules were not effective until 1990, but the

Public Citizen findings are a reminder that many

licensees had operated their plants 10 years or

longer before the NRC rule became effective, and

many licensees will have to accelerate their

collection schedules. The report also found that

about one-third (34 percent) of decommissioning

funds remained in internal funds in 1990.130

IM H, Hiller, ‘ ‘Investment s@ate@s for Nuclear Decommissioning and Pension Funds: Highlighting the Differences, ’ SidOmOn Brothers,

Inc., Bond Portfolio Analysis: Nuclear Decommissioning, Apr. 14, 1989, p. 5,

126 ~ce for exmple, P.C. Stimes and R.T Fl*ertY~

,, “Investment Management for Nuclear Decommissioning Trusts, ” Public Utilities

Formighd~, vol. 126, No. 11, Nov. 2, 1990, pp. 32-33; and M.D. Weinblatt, S. D’Eli~ and T.A. Haven, ‘‘Choosing Investment Strategy for

Qualified Nuclear Plant Decommissioning Trusts,” Public Utilities Fortnight[y, vol. 122, No. 10, Nov. 10, 1988, pp. 33-36.

127 EnerW policy Act of 1992, Public Law 102486, 106 Stat. 3024-3025> ‘m 19 17”

In J. Pryde, ‘ ‘Nuclear Decommissioning Funds Are Unlikely To Fully Elimina te Municipal, Analysts Say,’ The Bond Buyer, vol. 302, No.

29021, NOV. 3, 1992, p. 1.

IZ9 D Borson ~bli~ Citizen cnti~ wss Energy ~ojec~ Payment Due:A Reactor-by -ReactorAssessment of the NUclear IndU.my’s $25+

Billion Decommissioning Bill (Washingto@ DC: Public Citize~ Oct. 11, 1992), p. 2.

I

N Ibid., p. 3.
I

Case Studies

of Nine

Operating

Plants 5

I

n order to learn in detail some of the current plans,

activities, costs, and other issues related to commercial

nuclear power plant life attainment, life extension, and

decommissioning, the Office of Technology Assessment

supported a study to examine five sites with nine operating

plants.

l This chapter is adapted from that study. The issues

examined were performance and operating history, plans and

activities towards license renewal, and current plans for decommissioning. The selected units span a wide range of ages, sizes,

and designs, reflecting the diversity of the 108 nuclear power

plants operating in the United States today.

The Frost step was to select plants for review that were

representative of the diversity of U.S. nuclear power plants and

that had experience with life attainment, license renewal, and

decommissioning. To capture some of the diversity in plant

designs, reactors from three of the four commercial nuclear

suppliers were chosen. General Electric exclusively supplies

boiling water reactors (BWRs), while there are three suppliers of

pressurized water reactors (PWRs), Westinghouse, Combustion

Engineering, and Babcock and Wilcox.

In addition, plants with a range of power capacities and ages

were selected. A number of older plants, such as Oyster Creek

and San Onofre Unit 1, were designed and constructed before

substantial experience was obtained with commercial nuclear

power. These older plants do not have the same kinds of systems

and equipment found in larger and more recently constructed

plants, but some face early decommissioning or life extension

decisions now.

‘ ABZ, Inc., “Case Studies of Nine Operating Nuclear Power Plants: Life

Attainmen~ License Renewal and Decommissioning,’ contractor report prepared for the

OffIce of Technology Assessment, February 1993.

I I

Pit-. .

{ “t

I I

I 149
150 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Under these considerations, the five sites

selected were Calvert Cliffs, Hope Creek, Monticello, Salem, and the San Onofre Nuclear

Generating Station (SONGS). Calvert Cliffs is a

two-unit site with 845 megawatt-electric (MWe)

Combustion Engineering reactors that both began

operations in the mid-1970s. Salem is also a

two-unit site, but with Westinghouse reactors,

each rated at 1,106 MWe. Salem Unit 1 began

operation in June 1977, and Unit 2 began

operation in October 1981. The start delay

between the units was caused primarily by the

performance of upgrades (backfits) required after

the accident at Three Mile Island Unit 2.

Hope Creek is a 1,031-MWe General Electric

reactor that began operation in December 1986.

The unit is a fourth generation BWR with

enhanced safety features similar to the most

current (sixth) generation. Earlier BWR designs

such as Oyster Creek and Nine Mile Point Unit 1

are second and third generation units. The majority of BWRs are fourth and fifth generation plants

similar to Hope Creek. Monticello is a third

generation BWR and, until recently, was the

industry’s lead plant for license renewal. In terms

of systems and design, Monticello is reasonably

representative of the later BWR product line built

in the 1970s.

The SONGS site has three units. SONGS Unit

1 is one of the first Westinghouse PWRs; the unit

went on line in 1967 and was retired in 1992

pursuant to an agreement with the California

Public Utilities Commission. SONGS Units 2 and

3 are larger, Combustion Engineering plants that

went into service in the mid-1980s.

Despite an abundance of publicly available

information, many details about commercial nuclear power plants contained in Federal Government and other reports are missing, elusive, or

difficult to interpret. For example, detailed breakdowns of utility operations and maintenance

(O&M) expenses are not publicly available and

would be difficult to reconstruct; consequently,

significant additional research and analysis would

have been necessary to understand in detail the

underlying causes for the rise in O&M costs over

the past several years at these plants. In addition,

the U.S. Nuclear Regulatory Commission (NRC)

ranks operating plant performance by systematic

assessment of licensee performance (SALP)

scores, which range from 1 (good) to 3 (needs

improvement). The impact of SALP scores on

utility management is difficult to quantify, because the link between scores and subsequent

corrective actions is difficult to trace with publicly available data.

CALVERT CLIFFS CASE STUDY2

1 Performance and Operating History

The Baltimore Gas and Electric Co. (BG&E) in

Maryland owns and operates two nuclear power

units at its Calvert Cliffs site. Both units are

845-MWe PWRs constructed by Bechtel. The

nominal 40 year license period for both units has

been established, recovering the time used for

construction. BG&E applied for this extension in

June 1984, and the NRC approved in May 1985.

The recovered time used during construction

enables both units to operate a total of 12

reactor-years beyond their original license periods. This action is consistent with industry

practice. A summary of the construction and

licensing history for Calvert Cliffs is listed in

table 5-1.

Records indicate that BG&E operated both

units at Calvert Cliffs in an above average manner

until the late 1980s, with good reliability and

safety records. Lifetime capacity factors for both

units equal or slightly exceed industry averages.

With the exception of scheduled outages, Calvert

Cliffs did not experience significant outages until

2 Unless noted otherwise, all information in the discussion of this plant is from personal communication between Baltimore Gas and Electric

Co. (,BG&E; Barth Doroshuk), ABZ, Inc. (Edward Abbott and Nick Capik), and the Office of Technology Assessment (Robin Roy and Andrew

Moyad) orL and subsequent to, June 9, 1992.
Chapter 5--Case Studies of Nine Operating Plants I 151

Table 5-1—Calvert Cliffs Construction and Licensing History

Construction

Date of cost (year of Operating Lifetime

construction expend iture, license Commercial License capacity

permit in millions) start date operation expiration factor

Unit 1. . . . . . July 1969 $428.7 July 1974 May 1975 July 2014 67 percent

Unit 2. . . . . . July 1969 $329.7 November 1976 April 1977 April 2016 70 percent

SOURCE: ABZ, Inc., “Case Studies of Nine Operating Nuclear Power Plants: Life Attainment, License Renewal and Decommissioning,” contractor

report prepared for the Office of Technology Assessment, February 1993

1989. BG&E held its operating and maintenance

costs below the industry average until the late

1980s (figure 5- 1). With the exception of backfits

performed between 1980 and 1983—largely in

response to the Three Mile Island (TMI) accident—

there were no major capital additions at Calvert

Cliffs (figure 5-2). Other NRC performance

indicators for Calvert Cliffs are summarized in

table 5-2 (values are for both units combined).

The lack of significant safety issues until the late

1980s helped BG&E maintain operating costs

significantly below the industry average.

Figure 5-1—Calvert Cliffs Non-Fuel Operation and

Maintenance Costs (1991 dollars per kilowatt)

100 :

0! I I

1969 1973 1977 1981 1985 1989

SOURCE: ABZ, Inc. “Case Studies of Nine Operating Nuclear Power

Plants: Life Attainment, License Renewal and Decommissioning,”

contractor report prepared for the Office of Technology Assessment,

February 1993.

In the late 1980s, performance at Calvert Cliffs

degraded significantly. First, BG&E identified

several problems with engineering support and

system maintenance. Second, the NRC fried the

utility $300,000 in March 1988 for failing to

certify the ability of certain electrical equipment

to perform in cases of hot, wet, and high radiation

conditions that could result from a severe accident. When informed of the violation, BG&E shut

down Unit 1 for 2 months to evaluate the problem.

(Unit 2 was shut down at the time.) To remedy the

problem, BG&E qualified or replaced most of the

affected equipment.

Figure 5-2--Calvert Cliffs Capital Additions

(1991 dollars per kilowatt)

40 ~-—I

1 

L-----2!

:69 71 73 75 77 79 81 83 85 87 89

,—1

SOURCE: ABZ, Inc. “Case Studies of Nine Operating Nuclear Power

Plants: Life Attainment, License Renewal and Decommissioning,”

contractor report prepared for the Office of Technology Assessment,

February 1993.
152 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Table 5-2-Performance Indicators for Calvert Cliffs

1985 1966 1987 1966 1889 1990 1991

Total scrams. . . . . . . . . . . . . . . . . . . . . 7 7 8 4 0 0 2

Scrams > 15% per 1,000 hours . . . . . 0.99 0.75 0.46 0.27 0 0 0.06

Scrams < 15% per 1,000 hours. . . . . 0 0.13 0.13 0 0 0 0.13

Safety system actuations . . . . . . . . . . 2 1 2 4 2 2 1

Significant events. . . . . . . . . . . . . . . . 5 2 8 2 2 0 0

Safety system failures. . . . . . . . . . . . . 7 1 4 0 7 8 5

Forced outage rates (%). . . . . . . . . . . 5.6 7 3.38 5.13 1.75 1.88 1.88 9.38

Equipment forced out per 1,000hours. 1.01 0.60 0.70 0.25 0.24 0 0.54

Critical hours. . . . . . . . . . . . . . . . . . . . 8,017 15,348 12,554 14,249 3,573 1,925 6,687

SOURCE: ABZ, Inc., “Case Studies of Nine operating Nuclear Power Plants: Life Attainment, License Renewal and

Decommissioning,” contractor report prepared for the Office of Technology Aeseeement, February 1993.

BG&E performance during this period led the

NRC to add Calvert Cliffs to its “Problem

Plants” list, which increases NRC oversight. In

1989, BG&E was freed an additional $75,000 for

violations involving management oversight and

the control of plant activities. In March 1989, Unit

2 was shut down after BG&E discovered cracks

in its pressurizer heater sleeves. Subsequent

analysis determined intergranular stress corrosion

cracking (IGSCC) as the cause. Unit 1 continued

operating until its next planned refueling shutdown that May, but subsequent inspections found

no evidence of IGSCC in that unit as well. BG&E

suspected that the Unit 2 heater sleeves were more

susceptible to IGSCC, because they were reamed

(enlarged) during manufacturing to ease the

installation of heater elements.3 Replacement

power costs during the resulting outage were

estimated at $300,000 per unit per day. In part

from uncertainty about the utility’s restart schedule, as well as uncertainty over recovery of

replacement power costs, BG&E’s credit ratings

were downgraded.

Due to declining performance in the late 1980s

and uncertainty related to the heater sleeve

cracking, the NRC issued a confirmatory action

letter in 1989 preventing the restart of both units.

The utility was required to develop corrective

action plans for NRC approval. The units were

shutdown for several months, after which time the

NRC approved the BG&E plan. The corrective

action stipulated procedural upgrades and increased training. These actions, as well as the

increased maintenance that occurred during the

shutdown, led to a significant increase in O&M

costs.

Of the nearly 100 licensee event reports (LERs)

submitted to the NRC by BG&E since 1988, the

NRC rated 3 as significant events, down from the

average number of significant events reported in

prior years. Table 5-3 summarizes the 3 significant events at Calvert Cliffs that occurred between 1989 and 1991. In addition, the problems

at Calvert Cliffs in the late 1980s are reflected by

poor SALP scores during this period. These

scores began improving in late 1989 when the

NRC noted a substantial change in management

attitude that led to aggressive efforts to improve

performance. Complete SALP data for Calvert

Cliffs are summarized in table 5-4. Notably, the

problems of the late 1980s did not have a clear

effect on NRC performance indicators at Calvert

Cliffs, with the exception of a decline in critical

hours.

BG&E is planning or considering several

major capital improvements, including the addition of three diesel generators and steam generator replacements. Revised NRC guidance on

station blackout accidents prompted the addition

of the diesel generators; estimated costs are $130

J Nucleonics Week, vol. 30, No. 36, Sept. 7, 1989.
Chapter 5-Case Studies of Nine Operating Plants 153

million. BG&E has no definite plans for steam

generator replacement but will monitor the performance and material condition of the existing

units. Estimated costs are $100 million to $200

million per unit, excluding replacement power

charges. A decision on steam generator replacement will probably be deferred until BG&E

decides whether to pursue license renewal.

During a recent (June 1992) maintenance

outage, BG&E employed 1,100 contractors to

supplement the 1,400 permanent staff at Calvert

Cliffs. The contractor support is expected to

decrease to roughly 400 after the outage. Approximately 50 of these remaining 400 contract staff

provide unarmed security to supplement the

armed BG&E force. The growth in BG&E’s

permanent staff from a low of about 200 in the late

1970s to its current number stems from several

factors, including increased regulatory requirements and the addition of an onsite engineering

organization. BG&E’s staffing levels are within

the typical range for the industry. Increased

contractor support during outages is primarily the

result of additional craft labor to perform outagerelated work such as turbine overhaul, periodic

inspections, and major system modifications.

I Life Attainment and License Renewal

Based on internal economic analyses, BG&E

currently regards license renewal as desirable, but

a final decision is not expected until 1999. In the

meantime, the utility has implemented an integrated program to maintain the material condition

of systems, structures, and components (SSCs)

through the current and any renewed license

terms. The goal of the program is to achieve good

performance up to and possibly beyond the

current plant lifetime, including any preparations

for decommissioning. This life-cycle management program includes several phases:4

Table 5-3—Summary of Significant Events

at Calvert Cliffs

Unit Date Description

Unit 2. . . . . 3/01/89 Failure of throttle trip valve in a

turbine-driven auxiliary feed pump,

with resulting control room fire.

Unit 2. . . . . 5/05/89 Boric acid buildup on pressurizer

heaters.

Unit 2. . . . . 12/20/89 Licensee discovered nonsafety section of piping in service water

system could rupture in an earthquake and thus interrupt the flow

of safety-related service water to

the auxiliary building and the emergency diesel generators.

SOURCE: ABZ, Inc., ‘(Case Studies of Nine Operating Nuclear Power

Plants: Life Attainment, License Renewal and Decommissioning,”

contractor report prepared for the Office of Technology Assessment,

February 1993.

System screening to identify components either

important to license renewal (ITLR) or important to power production (ITPP).

Analysis of ITLR and ITPP components to

identify life cycle management requirements

for continued service.

Evaluation of the effectiveness of existing

programs in addressing life-cycle management

issues.

Implementation of new or modified programs

and evaluation of the generic applicability of

lessons learned.

Review of existing plant maintainability and

reliability. This phase includes an evaluation of

potential major improvements that could lead

to significant nuclear safety and personnel

benefits.

This integrated program is intended to provide

information needed to optimize life-cycle decisions. Program costs are $5 million per year, and

$1 million is cofunded by the Electric Power

Research Institute (EPRI). BG&E has finished

reviewing one system (the salt water cooling

system) and has begun to review four others:

control room and switchgear heating, ventilating,

4 Baltimore Gas and Electric Co., “Life Cycle Management Program,” June 9, 1992.
d

Table 5-4-Summary of Calvert Cliffs SALP Scores

Safety

Assessment Plant Radiological Maintenance/ Emergency Engineering assessment/quality

period operations controls surveillance preparedness Security technical support verification

1/90-3/9. . . . . . . . . 2 2 2 2 1 2 2

12/88-12/89. . . . . . 3 2 3 2 1 2 3

9187-1 1/88. . . . . . . 2 1 2 2 1 2 3

Quality

programs and

administrative Training

Assessment Plant Radiological Fire Emergency controls Licensing and qualification

period operations controls Maintenance Surveillance protection preparedness Security Outages effecting quality activities effectiveness

5/86-8/87. . . . . . . . 2 1 2 2 N 2 1 1 2 2 2

1O/84-4/86. . . . . . . 2 1 2 1 N 1 1 2 2 1 2

1O/83-8/84. . . . . . . 1 1 2 2 1 1 1 1 N 1 N

10182-9/63. . . . . . . 2 2 3 3 1 2 1 2 N 2 N

10181 -9182. . . . . . . 2 1 2 1 1 1 2 1 N 2 N

10179-9180 . . . . . . . 3 2 3 2 2 2 3 2 3 N N

NOTE: Category 1 indicates superior performance, where reduoed NRCattention maybe appropriate; Category 2indicates good performance andaracom rnendation tornaintain normal NRC attention;

Category 3 indicates acceptable performance, where NRCmayconsiderincreased inspections, andCategory Nindicates insufficient information tosupportan assessment- Asthesecategories suggest,

the NRC SALP rankings include no failing grades.

SOURCE: ABZ, Inc., “Case Studies of Nine Operating Nuclear Power Plants; Life Attainment, License Renewal and Decommissioning,” contractor report prepared for the Office of Technology

Assessment, Februaty 1993.

:

s

(D

1-

-.

a’
Chapter 5--Case Studies of Nine Operating Plants 1155

and air conditioning (HVAC) systems; compressed air; containment structures; and the reactor coolant system including the reactor vessel.

BG&E believes this program has already paid off

by redirecting efforts to upgrade the salt water

cooling system. Although the utility has not yet

decided whether to pursue license renewal, information from the life cycle management program

provides the foundation for a license renewal

application.

A joint EPRI-BG&E project has addressed

concerns about information storage retrieval for

the plant. PC-based software was developed to

ease the organization, storage, and retrieval of life

cycle information. The system, named "LCMDATA"

(for ‘‘life cycle management data’ ‘), will support

evaluations of material conditions relevant to

age-related degradation. Both text-based and

graphical information can be stored and retrieved.

The system will document evaluations and provide information to assist a license renewal

application should BG&E decide to pursue one.

BG&E may expand LCMDATA to track equipment covered by the recent NRC maintenance

rule.

BG&E is currently concerned about potential

reactor vessel embrittlement during a particular

accident sequence at the end of plant life.

Specifically, BG&E must demonstrate that embrittlement will not eliminate the margin of

protection against Unit 1 vessel failure from a

small-break, loss-of-coolant accident at the end of

plant life, where vessel pressure remains high

while the vessel downcomer is cooled by the

safety injection system. Analysis of the Calvert

Cliffs vessels indicates that Unit 2 is adequate for

more than 60 years, but Unit 1 is projected to

require further analysis to operate beyond 2005 (9

years before current license expiration). Different

fabrication techniques and materials are responsible for the relative vulnerability of Unit 1

compared to Unit 2. While no decision has been

made yet, BG&E is considering several solutions

to the Unit 1 problem: demonstration of slower

than assumed embrittlement; reduction in the

neutron flux experienced by the vessel; modifications to heat the injection water; more thorough

analysis to alleviate current concerns; or vessel

annealing.

The utility intends to keep license renewal as

an option, and in support of this effort, tailored the

Integrated Plant Assessment requirement of NRC’s

License Renewal rule to the plant’s service water

system.5 The NRC has informally recognized the

life-cycle management program at Calvert Cliffs

as an effective tool in the license renewal process.

In the meantime, no additional NRC inspections

or audits are anticipated beyond those that are

standard for the industry. Other than the programs

discussed above, there are no other significant

research efforts at Calvert Cliffs, except those

performed by the industry through groups such as

EPRI.

In 1989, BG&E applied for an NRC license to

construct an independent spent fuel storage installation (ISFSI) at the Calvert Cliffs site to provide

additional temporary spent fuel storage space

until the U.S. Department of Energy (DOE)

begins accepting the material.6 ISFSI construction began in April 1991 and completion is

scheduled for October 1992. The ISFSI will

provide enough additional spent fuel storage

space until 2003 at a cost of about $24 million,

which includes $18 million for capital costs and

$6 million for operations and maintenance. If

more space is necessary-which would be the

case if the DOE is not accepting spent fuel by

2003-additional space is authorized for operations until 2030.

5 Stone and Webster Engineering Corp., and Baltimore Gas and Electric Co., Service (Salt) Water System Lz~e-Cycle Management

Evaluation, EPRI TR-102204 (Palo Alto, CA: Electric Power Research Institute, April 1993).

6 Bal~ore Gas and Electric CO., ‘‘Calvert Cliffs Nuclear Power Plant Independent Spent Fuel Storage Installation Projecg Status Repon’

June 8, 1992.
156 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Table 5-5-Hope Creek Construction and Licensing History

Construction

Date of cost (year of Operating Lifetime

construction expenditure, license Commercial License capacity

permit In millions) start date operation expiration factor

Unit 1. . . . . . November 1974 $3,506.7 April 1986 December 1986 April 2026 81.9 percent

SOURCE: ABZ, Inc., “Case Studies of Nine Operating Nuclear Power Plants: Life Attainment, License Renewal and Decommissioning,” contractor

report prepared for the Office of T~nology Assessment, February 1993.

9 Decommissioning

BG&E owns 100-percent, undivided interest in

both Calvert Cliffs units. (When there are multiple owners of a nuclear power plant, decommissioning costs are generally divided according to

the proportion of ownership.) In a 1990 letter to

the NRC, BG&E noted its decision to use

qualified external sinking funds to provide financial assurance for decommissioning both units.7

Decommissioning costs of $137.3 million (1989

dollars) per unit were calculated using 10 CFR

50.75(c). Annual deposits to the external funds

will amount to $5.5 million for Unit 1 and $5.1

million for Unit 2. (Each rate is based on the

remaining lifetime of the respective unit.) In

1989, the Unit 1 fund was $414,165 below the

required amount, and the Unit 2 fund was $2.4

million above the required amount. At the end of

1989, the Unit 1 trust fund held $5.1 million and

the Unit 2 fund $7.5 million.

BG&E has made no formal plans for decommissioning but intends to begin investigating

options in 1993. Because both Calvert Cliffs units

have substantial time remaining in their operating

licenses, BG&E considers decommissioning planning premature at present. No analysis of decommissioning options has been performed yet, and

the impact of premature retirement or license

renewal of either unit has not been analyzed. The

lack of specific action towards these issues for

units of this age is consistent with common

industry practice.

HOPE CREEK CASE STUDY8

B Performance and Operating History

Hope Creek is a relatively young 1,031-MWe

BWR constructed by Bechtel and operated by the

Public Service Electric and Gas Co. (PSE&G) in

New Jersey. The single-unit plant is jointly

owned by PSE&G (95 percent) and Atlantic City

Electric (ACE) Co. (5 percent). The term of the

operating license is based on 40 years from the

date of approval, thus automatically recovering

the construction period. A summary of th e

construction and licensing history for Hope Creek

is listed in table 5-5.

Hope Creek’s performance since its recent

entry into commercial operation has been above

the industry average. NRC reviews of the plant

note a conservative, safety-conscious approach; a

sound management philosophy; good administrative programs; and skillful personnel-all reflected by both the lack of serious NRC regulatory

violations and good SALP ratings (table 5-6). The

plant’s critical operating time exceeds industry

averages and operating costs have equaled or

slightly exceed industry averages (figure 5-3).

NRC performance measures reveal one problem

area with Hope Creek relative to the industry

7 Baltimore Gas and Electric Co., “Calvcrt Cliffs Nuclcar Power Plant Units 1 and 2, Submittal of Certification of Financial Assurance for

Deeornmissioning, “ letter dated July 24, 1990.

8 Urdess noted othenvise, all information in the discussion of this unit is from personal communication between the Public Service Electric

and Gas Co. (PS~G; James Bailey et sJ.), ABz Inc. @.dward Abbott and Nick Capik), and the Ot13ce of lkchnology Assessment (Robin

Roy and Andrew Moyad) ou and subsequent to, June 1, 1992,
Table 5-6-Summary of Hope Creek SALP Scores

Safety

Assessment Plant Radiological Maintenance Emergency Engineering assessment/qualit y

period operations controls surveillance preparedness security technical support verification

8/90-3/92. . . . . . . . 1 1 2 1 1 1 1

5/89-7190. . . . . . . . 1 1 2 1 1 1 1

1188-4189 . . . . . . . . 1 1 2 2 1 2 2

Quality

programs and

administrative Training

Assessment Plant Radiological Fire Emergency controls Licensing and qualification

period operations controls Maintenance Surveillance protection preparedness security Outages effecting quality activities effectiveness

1286-1/88. . . . . . . 2 2 1 2 N 1 1 N 2 2 1

11/85-1 1/86. . . . . . 2 2 1 2 N 1 1 N 2 1 2

NOTE: Category 1 indicetessuperiorperformance, where reduced NRC attention maybe appropriate; Category 2indicates good performance and a recommendation to maintain normal NRC attenticm;

Category 3 ind”kates acceptable performance, where NRCmayconsiderincreasad inspections, and Category N indicates insufficient information tosupportan assessment. Asthesecategones suggest,

the NRC SALP rankings include no faiiing grades.

SOURCE: ABZ, inc., “Case Studies of Nine Operating Nuclear Power Plants; Life Attainment, License Ranewai and Decommissioning,” contractor report prepared for the Office of Technology

Assessment, February 1983.

o

-.

z
158 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Figure 5-3-Hope Creek Non-Fuel Operation and

Maintenance Costs (1991 dollars per kilowatt)

20 {’-x. /-----’

Hope Creek ->

Industry average - -> #

P

/

‘+

1969 1973 1977 1981 1985 1989

SOURCE: ABZ, Inc. “Case Studies of Nine Operating Nuclear Power

Plants: Ufe Attainment, License Renewal and Decommissioning,”

contractor report prepared for the Office of Technology Assessment,

February 1993.

(table 5-7). This area, the number of safety system

failures, has recently been addressed by a comprehensive review performed by the utility.

Since commercial operation began in 1986,

LERs have averaged 44 per year, which is above

the industry average, but most occurred in the first

2 years of operation. PSE&G attributes this larger

than average number to the reporting philosophy

at Hope Creek, where events are reported that

other utilities might not report. Consistent with

this explanation, the NRC has classified only one

LER in the past 5 years as significant. This single

event is summarized in table 5-8.

PSE&G has 2,200 permanent staff working at

its three units (Hope Creek and two Salem units),

administrative offices, and training center (located nearby). In addition to this staff, contractors

are hired for short-term projects, such as outage

work. About 500 to 600 contractors are necessary

to supplement the permanent staff for each unit

outage. With no outage, only 200 to 300 contractors are needed. Thispermanent contractor group

includes security personnel. In the mid-1980s

PSE&G evaluated which contractor positions

would be more appropriate for permanent staff.

However, no data are readily available regarding

the number of contractor positions eliminated, the

increase in permanent staff positions, or the net

effect on costs and performance.

H Life Attainment and License Renewal

Although the Hope Creek plant is relatively

new, PSE&G has initiated a Configuration Baseline Documentation Project to monitor the material condition of SSCs during the current and

any renewed license terms. Part of the motivation

for this long-term effort was a 52-day plant

Table 5-7—Performance Indicators for Hope Creek

1986 1987 1988 1989 1990 1991

Total scrams. . . . . . . . . . . . . . . . . . . . . . .

Scrams > 15% per 1,000 hours. . . . . . . .

Scrams < 15% per 1,000 hours. . . . . . . .

Safety system actuations, . . . . . . . . . . . .

Significant events. . . . . . . . . . . . . . . . . . .

Safety system failures. . . . . . . . . . . . . . . .

Forced outage rates. . . . . . . . . . . . . . . . .

Equipment forced out per 1,000 hours. .

Critical hours. . . . . . . . . . . . . . . . . . . . . . .

9

0.55

1.5

24

2

5

23

0.55

2,669

5

0.7

0

7

1

5

9.5

1.03

7,569

4

0.25

0

6

0

8

4,8

0.76

7,089

2

0.16

0

1

0

3

1.5

0.52

6,814

4

0.55

0

3

0

4

6.5

0.28

8,020

2

0.41

0

3

0

5

6.25

0.58

7,380

SOURCE: ABZ, inc., “Case Studies of Nine Operating Nuciear Power Plants: Life Attainment, License Renewai and

Decommissioning,” contractor report prepared for the Office of Technology e NRC may consider increased inspections, and

Category N indicates insufficient information to support an assessment. As these categories suggest, the NRC SALP rankings

include no failing grades.

Assessment, February 1993.
Chapter 5--Case Studies of Nine Operating Plants I 159

shutdown at Salem caused by incomplete design

information. Eighty-two systems at Hope Creek

are involved in the project, which is scheduled for

completion in 1998 at a total cost of $16 million

(excluding any maintenance needs identified

during the project). PSE&G claims this project

has improved understanding about plant design,

improved design control and engineering productivity, and formed a better foundation for evaluating potential design modifications. In addition,

PSE&G considers this program part of the foundation for future considerations of license renewal.

No deficiencies have been identified that would

preclude Hope Creek license renewal. Other than

those in the current revitalization program, no

significant capital additions are contemplated. No

other activities related to license renewal are

planned for the near future, and no significant

research efforts are being undertaken. Finally, no

additional NRC inspections or audits are anticipated other than those standard for the industry.

The Hope Creek operating license expires in

2026, but the unit’s spent fuel pool has sufficient

space for operations only until 2010. Although no

plans have been made for additional temporary

storage space, adequate space is available on the

site if new facilities (i.e., dry storage) become

necessary.

B Decommissioning

Hope Creek’s two joint owners (PSE&G and

ACE) will divide the decommissioning costs. In

a 1990 decommissioning report submitted to the

NRC, PSE&G estimated its share of decommissioning costs at $165.2 million (1990 dollars).9

To reach this amount, PSE&G will deposit $4,6

million annually in a qualified external sinking

fund. At the end of 1989, the PSE&G fund

Table 5-8-Summary of Significant Events

at Hope Creek

Date Description

10/10/87. . . . . . .Scram with safety relief valve stuck open

during surveillance testing.

SOURCE: ABZ, Inc., “Case Studies of Nine Operating Nuclear Power

Plants: Life Attainment, License Renewal and Decommissioning,”

contractor report prepared for the Office of Technology Assessment,

February 1993.

contained $13.9 million (1989 dollars). In its

1990 decommissioning report provided to the

NRC, ACE estimated its share of the total

escalated decommissioning cost at $8.7 million

(1990 dollars), which is deposited into an external

sinking fund at the rate of $226,000 per year.10

The expected value of the ACE fund at the time

of decommissioning is $13 million.

In addition to decommissioning reports submitted to the NRC, PSE&G has commissioned

two site-specific cost estimates for Hope Creek.

The frost study was performed by TLG Services,

Inc. (TLG) in 1987 and estimated total costs at

$350 million. A 1990 update by TLG increased

the estimate to $450 million (1990 dollars) .11

PSE&G claims that the increase is due to the

added costs of on site spent nuclear fuel storage,

increased labor rates, the development of more

realistic schedules for decommissioning activities, higher low-level waste compaction and

disposal charges, higher energy costs, and higher

insurance costs. PSE&G estimates the disposal of

radioactive waste will amount to 30 percent of the

total cost and may be underestimated because of

the uncertainty about the availability of disposal

sites in the future. These studies have not been

submitted to the NRC but are used as a basis for

the rate base.

PSE&G has not evaluated the potential impact

of early retirement for the Hope Creek facility.

9 Public Service Electric and Gas Co., “Hope Creek Generating Station Report and Certification of Financiat Assuran ce for

Decommissioning, ” July 1990.

10 A~mtlc El~~c Co, ‘‘Decommissioning Reports Relating to Atlantic Electric Compmy’s Ownership Interests in Hope Creek Peaeh

Bottom Units 2 and 3, and Salem Units 1 and 2,” letter dated July 26, 1990.

11 At fie time of ~1~ s~dy, tie deco~ssiofig cost up~te was involved in a rate case ad was not available fOr WVkW.
160 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

The 1990 decommissioning studies assume a

license period that recovers the construction

period. At present, PSE&G has not analyzed the

impact of license renewal on decommissioning

planning or funding. This is consistent with

industry practice.

The New Jersey State legislature is considering

legislation that would require the periodic review

of estimated decommissioning costs for nuclear

generating stations in the State.12 The intent of the

bill is to assure that adequate funds are available

for decommissioning at the end of plant operations. The bill includes reporting requirements for

decommissioning trust funds to monitor their

progress. The bill contains several significant

provisions:

New Jersey utilities must file site-specific or

site-adjusted decommissioning cost estimates by

January 1, 1993, and every 3 years thereafter.

Within 10 years of ending commercial operation,

the filing interval is reduced to 18 months.

Decommissioning cost estimates must document the current status and developing trends for

all activities that could affect decommissioning

costs, including the following:

■

■

■

■

■

■

actual decommissioning cost experience, both

foreign and domestic;

the development and use of state-of-the-art

equipment and techniques, such as robotics,

chemical cleaning methods, and waste processing methods;

the development of both high-level and lowlevel radioactive waste disposal sites and their

cost structures;

transportation methods and hardware;

applicable regulatory changes; and

estimates of insurance costs.

Annual reports on decommissioning trust funds

must be filed, documenting asset value, portfolio

mix, achieved returns, earnings indices (for benchmarking trust fund performance), and applicable

management fees. In addition, the New Jersey

Board of Regulatory Commissioners must be

notified of any changes in decommissioning trust

fired agreements.

This legislation provides for a written comment

period after information is submitted by utilities.

After such period, the Board would determine

whether funding levels require formal review

prior to future base rate filings. If so, the Board

would initiate proceedings, including a discovery

process, rights of intervention, and public and/or

evidentiary hearings.

MONTICELLO CASE STUDY13

B Performance and Operating History

Monticello is a 545-MWe General Electric

BWR constructed by Bechtel and owned and

operated by the Northern States Power (NSP) Co.

The single-unit plant entered commercial operation in January 1971, and the current license

expires in September 2010. The 2010 date includes the recovery of the construction period,

which extended the license 3 years. This extension was requested in February 1987 and granted

by the NRC in November the same year. A

summary of the construction and licensing history

for Monticello is listed in table 5-9.

Monticello reliability, as measured by length of

critical operations, has consistently surpassed the

industry average. Other performance indicators

reveal no weaknesses or other noteworthy trends.

Instead, these indicators and the periodic SALP

reviews suggest consistent plant reliability,

strong regulatory performance, and stable operations (table 5-10). There have been few significant events at Monticello; the NRC has recorded

12 New Jersey Board of Regulatory commissioners, ‘‘Nuclear Generating Plant Decommissioning Proposed New Rules, ” letter dated Mar.

6, 1992.

13 Udess noted o~e~se, M information in the discussion of this unit is from personal communication bdw- Northern Stab% power CO.

(NSP; lkrry Pickens et al.), ABZ, Inc. (Edward Abbott), and the Office of lkchnology Assessment (Robin Roy) o% and subsequent to, Oct.

27, 1992.
Chapter 5--Case Studies of Nine Operating Plants I 161

Table 5-9—Monticello Construction and Licensing History

Construct Ion

Date of cost (year of Operating Lifetime

construction expenditure, license Commercial License capacity

permit In millions) start date operation expiration factor

Unit 1. . . . . . June 1967 $119.1 January 1971 June 1971 September 2010 71.2 percent

SOURCE: ABZ, Inc.r “Case Studies of Nine Operating Nuclear Power Plants: Life Attainment, License Renewal and Decommissioning,” contractor

report prepared for the Office of Technology Assessment, February 1993.

only two in the last 5 years. These significant

events are summarized in table 5-11. A summary

of SALP scores for Monticello is listed in table

5-12.

Monticello O&M costs have been consistently

above the industry average with year-to-year

variations reflecting the added costs of refueling

outages (figure 5-4). In contrast, plant capital

additions have remained generally at or below

industry averages (figure 5-5). In 1983, NSP

replaced the stainless steel piping in the recirculation system and several connected branch systems

at Monticello. This piping is used for reactivity

control (i.e., control of reactor power during

operation) and was replaced due to its vulnerability to IGSCC. Consequently, there was a large,

one-time increase in capital additions.

NSP employs a staff of about 400 for all of

Monticello activities, including corporate support

and onsite personnel. Onsite staff numbers about

350: about 300 permanent employees and 50

contractors. To help control O&M costs, NSP has

performed recent reorganizations to reduce the

number of contractors and streamline the overall

organization.

B Life Attainment and License Renewal

Monticello was the second U.S. nuclear power

plant to initiate an application for NRC license

renewal as part of the lead-plant effort. NSP

began the process in September 1988 and anticipated preparatory costs of about $40 million over

6 or 7 years. This estimate included company

costs, NRC fees, contractor costs, legal expenses,

and public relations and communications costs.

Since 1988, NSP has spent about $9 million of its

own funds and about $4.5 million of DOE and

EPRI monies; thus, most of the funds budgeted

for the license renewal application remain. In

1992, NSP announced an indefinite deferral of the

filing of a license renewal application largely due

to uncertainties interpreting the NRC license

renewal rule and State concerns over spent fuel

disposal. For example, NSP noted its concern that

the number of reactor systems to be examined fo r

Table 5-10-Performance Indicators for Monticello

1985 1986 1987 1988 1989 1990 1991

Total scrams. . . . . . . . . . . . . . . . . . . . . 3 2 4 1 2 1 4

Scrams > 15% per 1,000 hours. . . . . 0.48 0.23 0.48 0.11 0.32 0.12 0.47

Scrams <15% per 1,000 hours. . . . . 0 0 0 0 0 0 0.5

Safety system actuations. . . . . . . . . . 0 2 1 0 1 0 3

Significant events. . . . . . . . . . . . . . . . 0 3 1 0 0 1 1

Safety system failures. . . . . . . . . . . . . 0 4 3 0 6 2 6

Forced outage rates. , . . . . . . . . . . . . 0.67 0.75 1.5 0.25 1,75 2.5 4.25

Equipment forced out per 1,000 hours. 0.15 0.12 0.37 0.12 0 0 0.12

Critical hours. ., . . . . . . . . . . . . . . . . . 6,427 6,984 7,174 8,769 6,679 8,487 7,076

SOURCE: ABZ, Inc., “Case Studies of Nine Operating Nuclear Power Plants: Life Attainment, License Renewal and

Decommissioning,” contractor report prepared for the Office of Technology Assessment, February 1993.
162 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Table 5-n-Summary of Significant Events

at Monticello

Date Description

9/1 1/90. . . . . . . Both emergency diesel generators were vulnerable to the potential failure of a nonseismic fire suppression pipe.

8/23191 . . . . . . . The original analysis of internal flooding

neglected to amount for the potential loss of

the diesels and redundant trains of electric

equipment. No other performance indicators

were involved.

SOURCE: ABZ, Inc., “Case Studies of Nine Operating Nuclear Power

Plants: Life Attainment, License Renewal and Decommissioning,”

contractor report prepared for the Office of Technology Assessment,

February 1993.

license renewal remained Unspecified, but had

increased from 74 to at least 104.

Two technical issues have arisen in the Monticello license renewal process that have led to

uncertainty over the practical interpretation of the

license renewal rule. First, in accordance with 10

CFR 50.49, plant electrical equipment must be

qualified to withstand the effects of an accident.

Monticello currently complies with the rule by

adhering to an Institute of Electrical and Electronics Engineers (IEEE) standard published in 1971.

This standard, along with other documents, comprises the Monticello equipment qualification

(EQ) program. The EQ program requires that,

when replacing any electrical equipment, NSP

must use equipment that is qualified based on a

subsequent 1974 standard with stricter requirements. This process of gradual replacements and

upgrades has been reviewed by the NRC, found

acceptable, and become part of Monticello’s

current licensing basis. However, based on discussions with NRC staff, Monticello believes it

may be required to upgrade to the 1974 standard

as a condition for license renewal. NSP estimates

that it would cost about $40 million, much of

which would be spent analyzing plant cabling.

NSP believes that most cabling would be found

acceptable based on similar analysis done by

Sandia Laboratories.

The second technical issue involves a potential

upgrade to a piping code that requires consideration of the conditions (“environment”) created

by the fluid within the pipe. Monticello piping

was qualified to an older American Society of

Mechanical Engineers (ASME) code when the

plant was constructed (ASME B31.1), whereas

plants built today must comply with another code

(ASME Section III). ASME is considering the

inclusion of “environmental factors” in an upcoming revision of the code. As a result, NSP

believes that the NRC staff will require such

environmental factors to be included in their

analysis of the adequacy of Monticello piping.

NSP, based on discussions with one member of

the code committee, believes that although not

explicit in ASME B31. 1, the code does implicitly

account for environmental factors. In addition,

NSP contends that its own inservice inspection

program would detect pipe cracking due to

environmental factors before pipe failure. Given

this inspection program and what it believes to be

the adequacy of the current piping requirements,

NSP believes upgrading to a yet unapproved

standard to renew the license is not needed.

In both cases, the current licensing bases for

Monticello are intended to provide an adequate

level of safety for continued operation for the time

remaining in the operating license. As such, NSP

believes the license renewal rule does not require

upgrading to new standards. The NRC staff,

however, believes such upgrades can be imposed

under the ‘‘regulatory oversight” portion of the

rule. NRC clarification is needed to resolve these

technical issues. In the interim, the Monticello

license renewal application has been indefinitely

deferred.

Before Monticello’s license can be extended,

the spent fuel pool at the plant will require

additional capacity. Without more fuel storage

capacity operations will need to cease by 2005.

(Currently, Monticello operates on 18 month fuel

cycles.) NSP already expanded spent fuel storage

capacity in 1978 with the addition of high-density

fuel racks. The utility may extend the fuel cycle

to 24 months and thereby extend the capacity of

the fuel pool to 2010.
Table 5-12-Summary of Monticello SALP Scores

Safety

Assessment Plant Radiological Maintenance/ Emergency Engineering assessment/quality

period operations controls surveillance preparedness Security technical support verification

3/89-6/90. . . . . . . . 1 2 1 1 2 2 1

12187-2189, . . . . . . 1 1 1 1 3 2 2

Quality

programs and

administrative Training

Assessment Plant Radiological Fire Emergency controls Licensing and qualification

period operations controls Maintenance Surveillance protection preparedness Security Outages effecting quality activities effectiveness

6/86-1 1187. . . . . . . 2 1 1 1 1 1 2 1 2 1 2

12184- 5186. . . . . . . 1 1 1 2 1 1 1 1 2 1 2

7/83-11/84. . . . . . . 1 2 1 2 2 1 1 1 2 1 N

7/82-6-83. . . . . . . 2 2 2 1 2 1 1 1 N 2 N

7/81-6183. . . . . . . . 1 2 2 1 2 1 1 1 N 1 N

7/80-6181. . . . . . . . 1 2 1 1 2 2 2 1 N N N

10/79-9/80. . . . . . . 2 3 2 2 2 3 2 2 2 N 2

NOTE: Category 1 indicates superior performance, where reduced NRC attention maybe appropriate; Category 2 indicates good performance anda recommendation to maintain normal NRC attention;

Category 3 indicates acceptable performance, where NRCmayconsiderincreased inspections, and Category Nindicates insufficient information tosupportan assessment. As these categories suggest,

the NRC SALP rankings include no faiiing grades.

SOURCE: ABZ, Inc., “Case Studies of Nine Operating Nuclear Power Pfants; Life Attainment, License Renewal and Decommissioning,” contractor report prepared for the Office of Technology

Assessment, February 1993.

o

g

m

z

-.

z
164 I Aging Nuclear Power Plants: Managing Plant Life

Figure 5-4--Monticello Non-Fuel Operation and

Maintenance Costs (1991 dollars per kilowatt)

I I

+’”

o“ i 1 I I 1 1 I I I I I I [ I I I I I I

1969 1973 1977 1981 1985 1989

SOURCE: ABZ, he. “Case studies of Nine Operating Nuclear Power

Plants: Life Attainment, Lieerwe Renewal and Deeommlesloning,”

contractor report prepared for the OMee of Technology Assessment,

February 1993.

To renew Monticello’s license, NSP will have

to build a dry cask storage facility. However, the

State of Minnesota requires a “certificate of

need’ before storage of spent fuel at the plant site

can be increased. NSP requested and received a

certificate of need to install the high-density spent

fuel storage racks in 1978 but has not yet

requested certification for the dry cask storage

facility. This application will be a milestone in the

license renewal process.

1 Decommissioning

NSP owns a 100 percent, undivided interest in

Monticello. In a 1990 decommissioning report

submitted to the NRC, NSP indicated a Monticello decommissioning trust fired target value of

$119 million (1986 dollars) .14 Initial annual

deposits into an external trust fund were projected

at $11.4 million. In subsequent correspondence,

and Decommissioning

Figure H-Monticello Capital Additions

(1991 dollars per kilowatt)

=,— I /1 I

I I

I

-50 ! I I I I I r I I I I I I I I I I I I

196 9 1973 1977 1981 1985

SOURCE: ABZ Inc. “Case Studies of Nine Operating Nuclear Power

Plants: Life Attainment, IJeense Renewal and Decommissioning,”

contractor report prepared for the Office of Twhnology Assessment,

Febfuary 1993.

NSP stated that the Minnesota Public Utilities

Commission denied their request for a rate

increase to collect these monies. Later, in 1991,

the utility was permitted to start recovering the

estimated decommissioning costs.

To evaluate decommissioning costs in more

detail, NSP commissioned TLG Engineering, Inc.

(TLG) to develop a site-specific estimate. Only

the DECON alternative was evaluated. This study

estimated decommissioning costs of $277.4 million (1990 dollars). The current collections for

decommissioning total $30 million: $9.7 million

in internal funds, $17 million in an external,

tax-qualified fund, and $3.6 million in an external, nonqualified fund. There has been no evaluation of the potential impact on decommissioning .

of premature retirement or license renewal at

Monticello.

14 Nofiem States Power CO., “Monticello Nuclear Generating Plant Amendxnent to Financial Assurance for Decommissioning,” letter

dated Sept. 6, 1990.
Chapter 5-Case Studies of Nine Operating Plants I 165

Table 5-13-Salem Construction and Licensing History

Construction

Date of cost (year of Operating Lifetime

construction expenditure, license Commercial License Capacity

permit In millions) start date operation expiration factor

Unit 1. . . . . . September 1968 $661.6 December 1976 June 1977 August 2016 58 percent

Unit 2. . . . . . September 1968 $614.3 May 1981 October 1981 April 2020 59 percent

SOURCE: ABZ, Inc., “Case Studies of Nine Operating Nuclear Power Plants: Life Attainment, License Renewal and Deeommissioning,” contractor

report prepared for the Office of Technology Assessment, February 1993.

SALEM CASE STUDY15

D Performance and Operating History

The two units at Salem have four owners:

Public Service Electric and Gas Co. (PSE&G),

Philadelphia Electric (PE), Atlantic City Electric

(ACE), and Delmarva Power and Light (DP&L).16

Both units are 1,106-MWe Westinghouse PWRs

and operated by PSE&G. The license terms for

both units reflect recovery of the time spent

during construction. The application for this

extension was made to the NRC in August 1987

and was approved in June 1991, resulting in the

recovery of almost 20 reactor-years of operating

time (total for both units). A summary of the

construction and licensing history for Salem is

listed in table 5-13.

In the early 1980s, Salem experienced several

operational difficulties that caused higher than

average operating costs (figure 5-6). Capital

additions costs have been average, though costs

were higher in the early 1980s, partly in response

to TMI-mandated backfits (figure 5-7). As indicated by critical operating time, Salem availability has been highly variable, but on average

similar to the rest of the industry. Other NRC

performance indicators are summarized in tabl e

5-14.

In 1983, a steam generator level transient at

Salem resulted in reactor shutdown. An analysis

of the sequence of events (leading up to and

following the rapid insertion of the reactor control

rods into the core) revealed that critical breakers

in the automatic shutdown circuits had failed to

operate. If the operators had not manually activated the circuit breakers, the event could have

caused significant plant damage. PSE&G was

Figure 5-6--Salem Non-Fuel Operation and

Maintenance Costs (1991 dollars per kilowatt)

Salem –—>

/

>4 ‘nd”’’vaverage

I 1 1 1 1 1 1 1 1 1 I I I 1

1969 1973 1977 1981 1985 1989

SOURCE: ABZ, he. ‘Y2=e Studies of Nine Operating Nueiear Power

Plants: Life Attainment, Lkense Renewal and Decommissioning,”

contractor report prepared for the Office of Technology Assessment,

February 1993.

IS Udess noted otheWise, alI information in the discussion of this plant is from WIXOIMI communication between Public se~iw El~~c

and Gas Co, (PSE&G; James Bailey et al.), ABZ, Lnc. (Edward Abbott and Nick Capik), and the Ofllce of lkehnology Assessment (Robin

Roy and Andrew Moyad) on, and subsequent to, June 1, 1992.

16 pSE&G and PE each own 42.59 pereent, and ACE and DP&L each own 7.41 ~c~t.
166 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Figure 5-7—Salem Capital Additions

(1991 dollars per kilowatt)

I I

-20 I I I I 1 I I 1

1969 1973 1977 1981 1985 1989

SOURCE: ABZ, Inc. “Case Studies of Nine Operating Nuclear Power

Plants: Life Attainment, License Renewal and Decommissioning,”

contractor report prepared for the Office of Technology Assessment,

February 1993.

freed a then-record $850,000.17 The NRC also

conducted a full scale investigation of the event,

which included almost every aspect of PSE&G’s

management at Salem. The NRC review led to

several significant and costly actions that resulted

in above average O&M costs at Salem. Once the

actions were completed, O&M costs decreased to

levels consistent with the rest of the industry.

The class of event that resulted in the failure of

the automatic shutdown system is called an

“anticipated transient without scram” (ATWS).

In the decade prior to the Salem event, the NRC

had been developing a specific ATWS rule to

address the potential consequences of such an

event. During that time, BWRs were considered

to be more susceptible to ATWS than PWRs, and

the NRC had required BWR owners to install

hardware modifications to make the event less

likely and more manageable. After the Salem

ATWS occurred, however, the NRC began to

require hardware upgrades, as well as reanalysis

of the likelihood of such events at PWRs.

In the late 1980s, the NRC noted several

problems at Salem, including periods of inadequate supervision, deficiencies in maintenance

and surveillance, and high numbers of personnel

errors. Over the past 10 years, Salem has submitted 995 LERs, averaging 46 per year at Unit 1 and

53 per year at Unit 2. This rate is 30 percent higher

than the industry average. PSE&G claims that this

larger than average number is due to the reporting

philosophy at Salem, where events are reported

that may not be at other facilities. In the last 5

years, the NRC judged three LERs as significant.

These three are summarized in table 5-15. Salem

received two additional NRC fines: a $50,000

fine in March 1988 for fire protection violations

and a $50,000 fine in April 1989 for violations

involving environmental qualification of electrical equipment.

In November 1991, the main turbine and

generator at Unit 2 sustained severe damage when

the turbine failed to trip during testing.18 An NRC

investigation stated the accident was ‘ ‘preventable.’ More than a year before the failure, PSE&G

found similar equipment for the Unit 1 turbine

inoperative due to mechanical binding. Although

PSE&G stated that the matching equipment in

Unit 2 would be replaced during its next outage,

no replacement was made. Subsequent investigation identified that the Unit 2 equipment was

immobilized by foreign debris, rust, and corrosion. Including the costs of replacement power,

repairs cost approximately $76 million. The root

cause of this failure was identified as the lack of

preventive maintenance, surveillance testing, and

procedural compliance.19

A summary of SALP scores for Salem is

provided in table 5-16. While these scores reflect

the problems of 1983 and 1989, they do not

17 Nucleonics week, VO1. 33, No. 31, Jdy 30, 1992.

18 Nucleonics Week, vol. 33, No. 31, J~y 30, 1992.

19 Inside Nllc, VO1. 13, No. 22, NOV. 4, 1991.
Chapter 5-Case Studies of Nine Operating Plants 1167

Table 5-14—Performance Indicators for Salem

1985 1986 1987 1988 1989 1990 1991

Total scrams..................,.. 1 0 18

Scrams > 15% per 1,000 hours. . . . . 0.86 1.41

Scrams < 15% per 1,000 hours. . . . . 0.13 0.5

Safety system actuations. . . . . . . . . . 2 3

Significant events. . . . . . . . . . . . . . . . 1 6

Safety system failures. . . . . . . . . . . . . 0 6

Forced outage rates. . . . . . . . . . . . . . 15.83 15.25

Equipment forced out per 1,000 hours, 1.44 2.19

Critical hours, . . . . . . . . . . . . . . . . .. .11,450 12,726

5

0.27

0.13

0

3

13

4.623

0.50

12,836

9

0.89

0

1

1

8

12.5

2.01

12,930

6

0.84

0.13

4

1

5

16.5

1.73

13,926

5

1.39

0

5

0

8

24.5

2.78

11,405

2

0.22

0

2

1

9

9.25

0.41

13,897

SOURCE: ABZ, Inc., “Case Studies of Nine Operating Nuclear Power Plants: Life Attainment, License Renewal and

Decommissioning,” contractor report prepared for the Office of Technology Assessment, February 1993.

appear to anticipate the 1991 turbine accident. In

fact, the category for operations actually improved in 1990.

Staffing. See Hope Creek, above.

1 Life Attainment and License Renewal

PSE&G has initiated several programs to

monitor and improve the material condition of

SSCs during the current and any renewed license

terms:

Revitalization: This 5-year program is aimed at

upgrading systems and components to increase

their productivity and reliability and to reduce

long-term costs. No budget has been established, and the net impact on cost and performance is yet to be determined.

Configuration Baseline Documentation Project: Part of the motivation behind this project

was a 52 day plant shutdown at Salem that

resulted from incomplete design information.

The program covers 54 Salem systems and

completion is scheduled in 1996 at a total cost

of $14 million (not including any ensuing

expenses). PSE&G maintains that this program

has improved their understanding of plant

design, improved design control and engineering productivity, and provided a better foundation for evaluating design modifications. In

addition, PSE&G considers this program a

sound foundation for any future considerations

of license renewal.

Five-Year Life-Cycle Management Program;

Initiated in 1991, this program consists of

system reviews to identify age-related degradation of SSCs. In 1992, four systems were

reviewed.

PSE&G has identified no significant issues that

would preclude license renewal for the Salem

units, although the utility has not performed a full

assessment of the NRC requirements. At present,

no additional NRC inspections or audits are

Table 5-15-Summary of Significant

Events at Salem

Unit Date Description

Unit 1 12/09/87 Procedural and testing inadequacies

in the reactor protection and control systems.

Unit 1 5120/89 Loss of RHR due to inadvertent

discharge of the nitrogen accumulator.

Unit 2 1 1/09/91 Severe damage due to a turbine

overspeed, which occurred from

the failure of the emergency trip

and overspeed protection solenoid valves (SOVs). The SOVs

failed due to mechanical binding

caused by foreign material,

sludge, rust, and corrosion.

SOURCE: ABZ, Inc., “Case Studies of Nine Operating Nuclear Power

Plants: Life Attainment, License Renewal and Decommissioning,”

contractor report prepared for the Office of Technology Assessment,

February 1993.
ii

Table 5-16-Summary of Salem SALP scores

Safety

Assessment Plant Radiological Maintenance/ Emergency Engineering assessment/quality

period operations controls surveillance preparedness Security technical support verification

8/90-12/91 . . . . . . . 2 2 2 1 1 2 2

5/89-7/90. . . . . . . . 2 2 2 1 1 2 2

1/88-4/89. . . . . . . . 3 2 2 2 1 2 2

Quality

programs and

administrative Training

Assessment Plant Radiological Fire Emergency controls Licensing and qualification

period operations controls Maintenance Surveillance protection preparedness Security Outages effecting quality activities effectiveness

10/86-12/87. . . . . . 2 2 1 2 N 1 1 1 1 2 2

10/85-9/86. . . . . . . 2 1 1 2 N 1 1 2 2 2 2

9/84-9/85. . . . . . . . 2 1 2 2 2 2 1 2 N 2 N

10/83-8/84. . . . . . . 3 2 2 2 3 2 1 2 N 2 N

10/82-9183. . . . . . . 3 2 2 2 2 1 2 1 N 2 N

9181 -8182 . . . . . . . . 2 1 1 1 2 2 3 1 N 2 N

7/80-6/81. . . . . . . . 1 2 1 1 2 2 3 1 1 N N

NOTE: Category 1 indicates superior performance, where reduced NRCattention may be appropriate; Category 2 indicates good performance and a recommendation to maintain normal NRC attention;

Category 3 indicates acceptable performance, where NRC may consider increased inspections, and Category N indicates insufficient information to support an assessment, Asthase categories suggest,

the NRC SALP rankings include no failing grades.

SOURCE: ABZ, Inc., “Case Studies of Nine Operating Nuclear Power Plants; Life Attainment, License Renewai and Decommissioning,” contractor report prepared for the Office of Technology

Assessment, February 1993.
Chapter 5--Case Studies of Nine Operating Plants I 169

anticipated other than those standard for the

industry.

1 Spent Fuel Storage

The Salem operating licenses expire August

2016 (Unit 1) and April 2021 (Unit 2). The Unit

1 spent fuel pool has sufficient temporary storage

space until 1998, assuming no loss in operational

full core reserve (a requirement imposed by the

NRC for continued operation). Unit 2 has adequate space until 2002, also assuming no loss in

operational full core reserve. Although no plans

have been made for additional temporary storage

space, adequate space is available on the site if

new facilities (i.e., dry storage) become necessary. PSE&G has developed plans to rerack both

spent fuel pools, which would permit continued

operation (with full core reserve) until 2007 for

Unit 1 and 2011 for Unit 2.

H Decommissioning

Salem’s four joint owners will divide decommissioning costs. In a decommissioning report

submitted to the NRC on July 24, 1990, PSE&G

estimated its share of the total estimated decommissioning cost at $60.5 million (1990 dollars)

per unit. PSE&G deposited this amount in a

qualified external sinking fired at the rate of $2.3

million per year for Unit 1 and $2.0 million per

year for Unit 2. Under applicable ratemaking

orders, decommissioning cost recovery is based

on a net negative salvage value of 20 percent. This

additional amount is included in PSE&G’s rate

base and will be added to the trust fund annually;

these funds will be treated as a prepayment for

future years. In 1989, trust fund balances were

$20.2 million (Unit 1) and $14.8 million (Unit 2).

Current fund requirements are based on a 1986

TLG study.

In a decommissioning report provided to the

NRC on July 26, 1990, PE established its share of

the total escalated decommissioning cost at $60.5

million (1990 dollars) per unit, which will be

deposited into either a decommissioning escrow

account or a qualified external sinking fund at the

rate of $2.3 million per year for Unit 1 and $2.0

million per year for Unit 2. PE anticipates that

most future payments will accrue in the trust

funds, while payments to the escrow accounts

would occur only to prevent the total contribution

from exceeding the amount permitted by the

Internal Revenue Code to retain tax qualification.

As of May 1990, the Unit 1 escrow account had

a balance of $4 million, and the trust fund had a

balance of $7 million. The Unit 2 escrow account

had a balance of $2.7 million, and the trust fund

had a balance of $6.14 million. PE estimates the

value of each trust fund will be $61 million per

unit when decommissioning begins.

In a decommissioning report provided to the

NRC on July 26, 1990, ACE established its share

of the total escalated decommissioning cost at

$10.5 million (1990 dollars) per unit. Deposits

will accrue in an external sinking fired at the

annual rate of $628,235 for Unit 1 and $721,307

for Unit 2. ACE estimates the value of this fund

will be $32 million for Unit 1 and $38 million for

Unit 2 when decommissioning begins. Estimates

of fund growth assume a 2 percent return after

taxes and inflation. The ACE funding requirements are based on the 1986 TLG study. Finally,

the PSE&G decommissioning report indicates the

DP&L funding share is $10.5 million per unit.

Annual DP&L deposits into an external sinking

fund are $400,000 for Unit 1 and $600,000 for

unit 2.

In addition to these decommissioning reports

submitted to the NRC, PSE&G commissioned

site-specific cost estimates for Salem. The first

study was performed by TLG in 1987 and

estimated decommissioning costs of approximately $376 million for both units, greatly

exceeding the estimates submitted to the NRC. A

1990 update increased the estimates to $450

million for both units. PSE&G maintains that the

increase is due to the increased cost of onsite

spent fuel storage, increased labor rates, development of more realistic schedules for decommissioning activities, higher charges for low-level
170 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

waste compaction and disposal, higher energy

costs, and higher insurance liability costs. PSE&G

estimates also that disposal of radioactive waste

will account for 30 percent of the total cost, which

may be an underestimate because of uncertainties

associated with the availability and costs of future

disposal sites. The TLG studies have not been

submitted to the NRC but are used for State utility

rate proceedings.

PSE&G appears to have conducted no formal

evaluation of the impact on decommissioning in

case of the premature retirement of either Salem

unit. Consistent with license renewal progress,

PSE&G has not modified their decommissioning

planning or funding to assess the potential of

license renewal. Both of these actions are consistent with common industry practice. Finally, as

mentioned in the Hope Creek discussion, legislation currently under review in the New Jersey

State legislature may affect future decommissioning planning for Salem.

SONGS CASE STUDY20

B Performance and Operating History

San Onofre is the site of three nuclear power

plants operated by Southern California Edison

(SCE). The San Onofre Nuclear Generating

Station Unit 1 (SONGS 1) began operation in

1968 as a demonstration project cofunded by the

Atomic Energy Commission. The unit is a threeloop Westinghouse PWR rated at 436 MWe,

although it has operated at less that 380 MWe in

recent years due to steam generator problems.

SONGS 1 is jointly owned by SCE (80 percent)

and San Diego Gas and Electric Co. (SDG&E, 20

percent), SONGS 1 was constructed for $88

million. Since then, modifications totaling $720

million have been made, including seismic qualifications, TMI modifications, fire protection,

standby power addition, environmental qualification, a sphere enclosure project, single-failure

analysis, security, and the systematic evaluation

program.

SONGS Unit 2 is a 1,070-MWe Combustion

Engineering PWR built by Bechtel; commercial

operation began in August 1983. SONGS Unit 3

is a 1,080-MWe Combustion Engineering PWR

built by Bechtel; commercial operation began in

April 1984. These two units are owned jointly by

SCE (75.05 percent), SDG&E (20 percent),

Anaheim Electrical Division (3.16 percent), and

Riverside Public Utilities (1.79 percent). There

have been no applications yet to recover license

time spent during construction of either Unit 2 or

Unit 3. A summary of the construction and

licensing history of SONGS is listed in table 5-17.

SONGS 1 has experienced prolonged periods

of nonoperation, primarily to fix and replace

equipment and to modify the facility to comply

with Federal regulations. Since the unit began

operation, the steam generators have been a

particular problem. Each generator consists of

approximately 11,000 tubes used to convert water

to steam. Of these tubes, over 1,400 (more than 10

percent) have been plugged due to damage and

leakage. Such plugging reduces steam generator

performance and thus the amount of electricity

generated. These problems prompted SCE in

1980 to insert sleeves into more than 6,900 tubes.

The sleeves extend tube life and reduce subsequent degradation. No other nuclear plant in the

United States has undertaken such a large-scale

sleeving program.

In accordance with the Full-Term Operating

License (FTOL), which was formally issued in

1991 for SONGS 1, SCE was required to complete several plant modifications prior to Fuel

Cycle 12, as directed by a 1990 NRC order.

(Before 1991, SONGS 1 had operated on a

provisional operating license.) The changes were

estimated to cost about $125 million and were

Zo Udess not~ o~e~ise, all information in tie discussion of this plant is taken from personal communication between Southern California

Edison Co. (SCE; Harold Ray, Joseph Wambold et al.), ABZ, Inc. (Edward Abbott and Nick Cap&), and the OffIce of lkdmology Assessment

(Robin Roy and Andrew Moyad) on, and subsequent to, Oct. 14, 1992.
Chapter 5-Case Studies of Nine Operating Plants

Table 5-17—SONGS Construction and Licensing History

171

Construction

Date of cost (year of Operating Lifetime

construction expenditure, license Commercial License capacity

permit in millions) start date operation expiration factor

Unit 1. . . . . . March 1964 $88.0 March 1967 January 1968 March 2004 53.8 percent

Unit 2. . . . . . October 1973 $2,540 August 1982 August 1983 October 2013 72.3 percent

Unit 3. . . . . . October 1973 $2,250 September 1983 April1984 October 2013 76.5 percent

SOURCE: ABZ, Inc., “Case Studies of Nine Operating Nuclear Power Plants: Life Attainment, License Renewal and Decommissioning,” contractor

report prepared for the Office of Technology Assessment, February 1993.

initiated as required. In parallel, SCE sought

CPUC approval for the required expenditures,

which the utility determined were cost effective.

However, the CPUC Division of Ratepayer Advocates (DRA) opposed approval based on its

own economic analyses, which found the plant

not to be cost effective. There were several areas

of disagreement between DRA and SCE involving such issues as future plant capacity factors,

future operating costs, potential steam generator

replacements, and SCE forecasts of replacement

power costs.21

In 1992, SCE, SDG&E, and the CPUC agreed

to close the 23-year-old plant, because of the

potential problems with cost effectiveness. Operations ceased at the end of Fuel Cycle 11 on

November 30, 1992. Under the agreement, SONGS

1 will be operated and staffed as usual until all

fuel is removed from the reactor vessel in late

1993. Thereafter, staffing and support requirements will decrease over the next 2 years to levels

appropriate for long-term plant storage. The

settlement agreement also allows SCE and SDG&E

to recover their remaining capital investments

over 4 years ($110 million for SDG&E and $350

million for SCE). The previously authorized rate

of return applied until Unit 1 was shutdown, and

the rate based on long-term debt has applied since

shutdown.

All fuel in the SONGS 1 reactor vessel will be

stored in its spent fuel pool. To provide sufficient

space for this full core offload, 49 fuel assemblies

now in the Unit 1 pool will be transferred to the

Units 2 and 3 pools. The SONGS site is licensed

for such fuel transfers between pools. Current

plans are to restrict all fuel storage to onsite pools,

but dry storage facilities may be considered in the

future to expand storage capacity. After fuel

removal, Unit 1 will remain in a long-term

shutdown mode. SCE has identified the systems

that will remain operable and those that will not.

The operable systems will primarily ensure the

safe storage of fuel in the pool.

Overall, SONGS performance is consistent

with industry averages. Despite earlier difficulties with Unit 1, final operations continued for

377 days. Total plant O&M costs are slightly

higher than average, a result of the higher cost of

living and thus higher salaries in southern California (figure 5-8). In addition, costs were higher

than normal when Units 2 and 3 frost came on line.

Federal Energy Regulatory Commission (FERC)

data on SCE capital additions provide little

information. From 1975 through 1983, capital

costs were significantly greater than average,

reflecting Unit 1 upgrades. Since then, FERC data

indicate below average costs for SCE (figure 5-9).

Aside from these FERC data, SCE forecasts

capital expenditures on a 5-year basis. Projected

costs for the next 5 years range from a low of $47

per kilowatt-installed to a high of $62 per

21 Ro~ M. ~osiaII, Re@ato~ ~OgHUU Specialist, Division of Ratepayer Advocates, Califofia Public UtihtieS COmmiSsiOL

memorandum to the ~lce of Technology Assessment, Feb. 8, 1993,
172 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Figure 5-8-Southern California Edison

(SONGS) Non-Fuel Operation and Maintenance

Costs (1991 dollars per kilowatt)

—.—

SONGS > tiL

,J&/--

< Industry average

1969 1973 1977 1981 1985 1989

SOURCE: ABZ, Inc. “Case Studies of Nine Operating Nuclear Power

Plants: Life Attainment, License Renewal and Decommissioning,”

contractor report prepared for the Office of Technology Assessment,

February 1993.

kilowatt-installed (in year of expenditure dollars).

These estimates include overhead costs.22

SCE’s performance indicators show no distinct

weaknesses or noteworthy trends. In response to

issues related to design basis documentation, SCE

has instituted a comprehensive program to prevent future problems (discussed in the next

section). SCE’s performance indicators are listed

in table 5-18. Events rated as significant by the

NRC in the last 5 years are summarized in table

5-19. Compared to other region IV licensees,

though, SCE continues to perform well; the

utility’s SALP scores are listed in table 5-20.

SCE employs a total of 3,500 people for the 3

units, about 2,400 of which are permanent staff.

About 2,300 employees are located at the plant

site, and the remainder work at headquarters. The

site employees are roughly divided as follows:

Security (234), Outage Management (36), MainFigure 5-9--Southern California Edison (SONGS)

Capital Additions (1991 dollars per kilowatt)

350

300-

!

50 i M\

1969 1973 1977 1981 1985 1989

SOURCE: ABZ, Inc. “Case Studies of Nine Operating Nuciear Power

Plants: Life Attainment, License Renewal and Decommissioning,”

contractor report prepared for the Office of Technology Assessment,

February 1993.

tenance (594), Operations (292), Emergency Preparedness (104), Training (137), Technical (165),

Chemistry (65), Health Physics (272), and Site

Support (326). According to SCE, staff size

peaked when Units 2 and 3 came on line but has

been decreasing ever since.

I Life Attainment and License Renewal

SCE has two active programs applicable to

both life attainment and license renewal: the

Current License Basis Program and the Design

Bases Documentation and Reconstitution Program. SCE is one of two utilities that has

volunteered to participate in an NRC pilot program to develop current licensing bases. The

nascent program is first gathering the necessary

documentation and investigating methods for

future computer retrieval. Anticipated meetings

with the NRC will help better define the requirements of the program and develop schedules. SCE

22 Recent correspondence be~een SCE ~d CPIJC SU~UK that WE has raised capital additions cost estimates for SONGS 2 and 3 to about

$70 per kilowatt. Robert M. K.inosiw Regulatory Program Specialist, Division of Ratepayer Advocates, California Public Utilities

Commissio% memorandum to the Office of ‘Ikchnology Assessmen4 Feb. 8, 1993,
Chapter 5--Case Studies of Nine Operating Plants I 173

Table 5-1 8—Performance Indicators for SONGS

1985 1986 1987 1988 1989 1990 1991

Total scrams. . . . . . . . . . . . . . . . . . . . . 14

Scrams > 15% per 1,000 hours. . . . . 0.74

Scrams < 15% per 1,000 hours. . . . . 0.17

Safety system actuations. . . . . . . . . . 4

Significant events. . . . . . . . . . . . . . . . 2

Safety system failures. . . . . . . . . . . . . 0

Forced outage rates. . . . . . . . . . . . . . 6.3

Equipment forced out per 1,000 hours. 0.53

Critical hours. . . . . . . . . . . . . . . . . . . . 4,708

14 4

0.56 0.16

0.33 0

1 1

4 2

2 1

10.2 2

0.74 0.24

5,624 7,134

0

0

0

1

4

13

1.9

0.08

6,012

3

0.13

0

2

2

9

18.7

0.95

5,687

3

0.13

0

1

0

4

2.8

0.17

6,051

3

.012

0

0

0

5

8.5

0.29

6,568

SOURCE: ABZ, klC., “Case Studies of Nine Operating Nuclear Power Plants: Life Attainment, License Renewal and

Decommission ing, ” contractor report prepared for the Off ice of Technology Assessment, February 1993.

expects to complete the development of the

licensing basis by June 1993 with a budget of

about $400,000.

SCE’s San Onofre Design Bases Documentation and Reconstitution program is designed to

retrieve, reconstruct, confirm, and document SONGS’s

nuclear power plant design bases in a series of

Design Bases Documents. The SCE Design Bases

Documentation (DBD) Program will document

the meaningful plant design bases and ensure

prompt access to the associated information. The

purpose is to record plant design at the time the

operating license was issued, as well as any

subsequent design modifications. The program

will document the original design bases to help

compare their consistency with existing design

details. SCE operating, maintenance, and engineering staffs will have access to the information.

With the shutdown of SONGS 1, the program

applies only to Units 2 and 3. Although the

program is not specifically designed to extend the

licensing of Units 2 and 3, its completion would

ease any effort to extend either plant license. The

DBDs will support a variety of engineering,

licensing, and plant operations activities. The

scope of the DBD Program includes systems

considered important to plant safety, systems

with safety-related functions, and select nonsafetyrelated systems. Systems covered in the plant

Technical Specifications are also included.

Table 5-1 9-Summary of Significant Events

at SONGS

Unit Date Description

Unit 1. . . . . .

Unit 1. . . . . .

Unit 2. . . . . .

Unit 3. . . . . .

Unit 1. . . . . .

Unit 1. . . . . .

1 2/1 2188 195 steam generator tubes may

not have been hard rolled, creating the potential for their disconnection from the tube sheet

in the event of a steam line

break accident.

12/1 2/88 An electrical design deficiency

could cause a non-class 1 E

swing bus not to load shed on

a diesel generator start with an

SI signal present. A single failure could cause loss of a diesel

generator, because a diesel

would be required to operate

above its T/S rating.

12/1 5188 19 valves in the CCW system

may fail during a seismic event,

which would render the CCW

system inoperable.

12/1 5/88 19 valves in the CCW system

may fail during a seismic event,

which would render the CCW

system inoperable,

2/2/89 Fasteners on thermal shield

support blocks were found broken. Event date unknown.

3/2/89 A design deficiency was found

in the EDG load sequence logic.

SOURCE: ABZ, Inc., “Case Studies of Nine Operating Nuclear Power

Plants: Life Attainment, Ucense Renewal and Decommissionlngf”

contractor report prepared for the Office of Technology Assessment,

February 1993.
Table 5-20-Summary of SONGS SALP Scores

Safety

Assessment Plant Radiological Maintenance/ Emergency Engineering assessment/quality

period operations controls surveillance preparedness Security technical support verification

2/90-7-91, . . . . . . 2 1 2 1 1 2 2

10/88-1/90. . . . . . . 2 1 1 1 1 2 2

10187-9188. . . . . . . 1 1 2 1 1 3 3

Quality

programs and

administrative Training

Assessment Plant Radiological Fire Emergency controls Licensing and qualification

period operations controls Maintenance Surveillance protection preparedness Security Outages effecting quality activities effectiveness

6/66-9/87. . . . . . . . 1 2 2 2 2 1 2 1 2 2 1

10184-5/86. . . . . . . 2 1 2 2 1 2 2 1 2 2 2

6/83-9/84. . . . . . . . 3 3 2 2 2 1 2 2 N 2 N

7181-5/83. . . . . . . . 2 2 2 2 2 1 2 1 2 2 N

6/80-6/81. . . . . . . . 2 3 3 1 2 1 3 1 2 N N

NOTE: Category 1 indicates superior performance, where reduced NRCattention maybe appropriate; Category 2 indicates good performance andarecom mendation to maintain normai NRC attention;

Category 3 indicates acceptable performance, where NRC mayconsiderincreasad inspections, and Category N indicates insufficient information tosupportan assessment. Asthesecategories suggest,

the NRC SALP rankings include no failing grades.

SOURCE: ABZ, inc., “Case Studies of Nine Operating Nuciear Power Plants; Life Attainment, License Renewal and I)ecornmissioning,” contractor report prepared for the Office of Technology

Assessment, February 1993.

i

r--.

3
Chapter 5-Case Studies of Nine Operating Plants 175

In general, the contents of self-contained documents are not duplicated in the DBD. Rather,

these documents are incorporated by reference,

when applicable. Examples of self-contained

documents include:

ASME Code Stress Reports.

Equipment Qualification Data Packages.

Vendor Manuals.

Operations and Maintenance Procedures.

Industry Codes and Standards.

Specifications.

Design Changes, Calculations.

Design Detail Drawings.

Select DBDs are validated through a process

intended to provide reasonable assurance the

DBD is complete, accurate, and consistent with

the existing as-designed, as-licensed, as-built,

as-operated, as-maintained configuration of the

plant. The scope of the validation process is

flexible and may vary from selective sampling to

comprehensive review of the information, depending on system factors such as importance to

safety, history of past problems, complexity, and

size.

The process of DBD program validation may

include any of the following: walkdowns performed by the DBD Engineer (DBD preparer)

during document preparation; supervisory review

during DBD preparation stages, which may include evaluation by an Independent Review

Engineer (IRE); and an interdisciplinary review

performed by technicians from Nuclear Engineering, Nuclear Licensing, Station Technical, and

other sections of the nuclear staff independent of

the DBD Section. DBD managers will select the

method of validation on a case-by-case basis.

B Decommissioning

SONGS Unit 1 is jointly owned by SCE (80

percent undivided interest) and SDG&E (20

percent undivided interest). In a decommissioning report submitted to the NRC on July 24, 1990,

SCE calculated its share of the Unit 1 decommissioning costs at $69.5 million (1986 dollars). This

amount was determined in accordance with the

formula for minimum financial assurance in 10

CFR 50.75. The California PUC has authorized

SCE to collect $190 million (1992 dollars) for

decommissioning costs based on a site-specific

cost estimate.

Because SONGS is located on Federal land,

SCE is required to return the site to its original

condition (’‘beach sand’ after operation. Therefore, the decommissioning cost estimate is greater

than the NRC mandated minimum (which considers radiological decommissioning only). Decommissioning funds are being deposited into an

external trust account (currently $18 million per

year). To date, SCE has collected $175 million.

No changes to the estimated decommissioning

costs have been made since the decision to

shutdown Unit 1 early.

In a decommissioning report submitted to the

NRC on July 24, 1990, SDG&E calculated its

share of the Unit 1 decommissioning costs at

$17.4 million (1986 dollars). This amount was

determined in accordance with the formula in 10

CFR 50.75. As required, SDG&E deposits are

made annually into an external trust.

Under current plans, SONGS 1 will be decommissioned by the SAFSTOR method. The shutdown and long-term storage of Unit 1 is planned

as four phases. The frost phase consisted primarily

of preparation for final shutdown and has already

been completed. The second phase consists of

performing a normal plant shutdown at the end of

the current refueling cycle and the removal of the

fuel from the reactor vessel to the spent fuel pool.

The third phase will prepare the unit for long-term

storage until Units 2 and 3 are decommissioned.

The fourth phase is decommissioning the unit in

accordance with an NRC reviewed and approved

decommissioning plan.

1 Phase 1: Preparation for Plant Closure

This phase includes the preparation and submittal of license amendments, detailed plans for

disposition of SSCs, review and evaluation of
176 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

station programs and procedures, and development of plans to reduce regulatory requirements

to reflect the unit’s defueled condition. These

plans were discussed during meetings with the

NRC. Information from other prematurely shutdown plants were gathered and analyzed with

respect to the unique situation at SONGS 1.

I Phase 2: Shutdown and Plant Closure

The unit was shut down in the second phase.

The shutdown occurred on November 30,1992, at

the end of fuel cycle 11. The generator output

breakers will be opened and the reactor coolant

system will be cooled down to permit disassembly of the reactor vessel. Concurrent with vessel

disassembly, 49 fuel assemblies from Unit 1 will

be moved to the spent fuel pools at Units 2 and 3

to allow the removal of the cycle 11 core. When

this fuel offload is completed, the reactor vessel

internals will be reinstalled in the vessel. The

vessel head will be placed back on the vessel but

not tensioned.

SSCs needed to store the fuel safely will

continue to operate in accordance with applicable

Technical Specifications. Other important operable systems include radiation monitoring, the

emergency diesel generators, radwaste processing, and the fuel handling equipment. The SSCs

not required to contain radioactive material will

be secured to prevent long-term degradation and

the inadvertent spread of contamination. Uncontaminated systems will be secured to minimize

occupational hazards. The detailed plans to accomplish these long-term storage activities are in

preparation,

Following shutdown, measures will be taken to

reduce personnel radiation exposure and ease

access to areas that may require monitoring.

These measures will include wearing lead blankets for shielding in hot spots and some decontamination. In addition, stored radioactive material such as spent resins and falters will be

disposed. If practicable, decontamination by system flushing to reduce general radiation will also

occur.

Storage plans include periodic monitoring to

ensure contaminated SSCs are not degrading.

Current plans outline an aggressive program to

reduce the need for active storage and monitoring

equipment. Ideally, all fuel in the Unit 1 spent fuel

pool will move to Units 2 and 3 to eliminate the

maintenance of equipment and systems needed to

cool and store fuel. In the interim, any SSCs not

required for spent fuel storage will be drained,

vented, and de-energized. The reactor coolant

system will be drained and vented. Some water

will remain at low points in the circulating loops

and in the reactor vessel but will evaporate with

time. The steam generators, residual heat removal

pumps, heat exchangers, pressurizer relief tank,

and the excess letdown and regenerative heat

exchanger will also be drained and vented. The

containment sump will be pumped dry.

Electric motors in the containment will be

de-energized; remaining oil will be removed to

reduce the fire hazard. All remaining fluid supplies to the containment will be isolated and any

remaining equipment such as lights secured. The

containment vent will be locked open to provide

a vent path to the plant stack. The equipment and

personnel hatches will be locked and posted.

Cathodic protection and periodic inspections

necessary to maintain the sphere, which contains

the radioactive material, will continue until Units

2 and 3 are decommissioned.

Equipment associated with the turbine generator will be secured. The condenser hotwell will be

drained. The feed and condensate systems including the condensate storage tank will be drained

and vented enough to prevent accidental flooding.

All drains and vents will remain open. All electric

motors will be secured by tagging their associated

breakers. The generator will be purged of hydrogen and vented. The hydrogen tanks and backup

nitrogen bottles will be returned to the vendor.

The turbine lube oil system will be drained and

cleaned. The lube oil reservoir will be emptied,

wiped down, and vented. Any motors containing
Chapter 5-Case Studies of Nine Operating Plants 177

oil will be drained. Salvageable equipment (e.g.,

the turbine generator) may be preserved until a

purchaser is found.

Equipment in the reactor auxiliary building

needed to maintain boron concentration in the

core will be secured. The work includes draining

and flushing the piping and pumps in the chemical volume control system, such as the boric acid

injection pump and the boric acid tank. The

radioactive material in the solid and liquid

radwaste systems will be processed, packaged,

and either stored onsite or sent to a burial site. The

solid and liquid radwaste systems will remain in

service during deactivation of potentially radioactive systems. This will permit processing of waste

generated when systems are drained. The fuel

pool cooling and clean up system will be the last

one vented and drained. The solid and liquid

radwaste systems, therefore, will probably remain

in service for at least 3 or 4 years.

Once all potentially radioactive material has

been processed, the solid, liquid, and gaseous

radwaste systems will be secured. To reduce the

potential for airborne contamination, preventiv e

measures will be taken, such as decontaminating .

floors, walls, and equipment surfaces. Final

radiation surveys of the rooms will be performed

and the rooms will be posted. All accesses to the

building will be locked and posted. Routine

building inspections will be performed, with the

frequency depending on ALARA (as low as

reasonably achievable) radiation exposure concerns and the anticipated degradation of the

equipment.

Once the fuel is transferred to Units 2 and 3, the

remaining operable systems will be secured. The

component cooling and salt water cooling systems will be drained and vented. The electrical

and air supplies will be positively isolated. The

spent fuel pool cooling and cleanup systems will

also be drained and vented. The water remaining

in the pool will be pumped out and processed and

the pool will be covered. The fuel handling

equipment and associated support systems will be

secured. The fuel storage building will be surveyed and posted. All accesses will be locked and

posted. Routine inspections will be performed

consistent with ALARA and any anticipated

degradation.

The labs, offices, and equipment shops in the

main building will be maintained as needed to

support work during plant storage. Some of the

facilities may support work for Units 2 and 3. As

a result, the HVAC systems will be maintained

for habitability, and lighting, fire protection,

water, and sewage systems will be maintained

too. Access to the control room, switchgear, and

cable spreading rooms will be limited to employees supporting the remaining active systems, such

as lighting.

Once the fuel has been removed from Unit 1,

round the clock coverage for the plant will

probably not be needed. The control room will be

secured by de-energizing the control and lighting

panels and then locked. Similarly, the cable

spreading and switchgear rooms will be deactivated and locked. The diesel generators will

be preserved to the extent needed to maintain their

commercial value. The fuel oil tanks and associated piping will be drained. Any energized

support systems such as starting air and control

panels will be secured. The diesel generator

rooms will be locked. Finally, ventilation systems

for areas containing radioactive material, such as

the containment and the reactor auxiliary building, will be aligned to provide a single vent path

through the Unit 1 stack. The ventilation system

and the stack monitor will remain in service until

the unit is decommissioned.

B Phase 3: SAFSTOR

Current plans call for the long-term storage of

Unit 1 until Units 2 and 3 are decommissioned. As

noted above, routine inspections will be performed consistent with ALARA goals and the

anticipated degradation of Unit 1 SSCs. A small

staff will perform such inspections routinely and

provide maintenance. In addition, this staff will

maintain any records required to support eventual
178 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

decommissioning, including descriptions of the

secured state of the plant such as marked-up

drawings, radiation surveys, and records of any

spills.

I Phase 4: Final Site Decommissioning

Under current plans, fourth phase will begin

when Units 2 and 3 are decommissioned. As

required by NRC decommissioning rules, a Unit

1 decommissioning plan will be submitted within

2 years after plant shutdown; the plan will be

updated as needed while Units 2 and 3 remain

operating. Given the lengthy storage period (in

excess of 20 years), advancements in decommissioning technologies such as decontamination

methods and waste volume reduction are likely.

As a result, changes to the Unit 1 plan are

anticipated. In addition, the decommissioning

options for Units 2 and 3 should be consistent

with Unit 1 and provide the same level of site

restoration.

Units 2 and 3 are owned by SCE (75.05 percent

undivided interest), SDG&E (20 percent undivided interest), the City of Anaheim (3.16 percent

undivided interest), and the City of Riverside

(1.79 percent undivided interest). All four of these

owners have provided for decommissioning financial assurance according to the formula in 10

CFR 50.75; all four have established separate

external trust funds to collect these monies. Their

respective funding shares to decommission units

2 and 3 were outlined in separate reports submitted to the NRC in July 1990 and are the following

(1986 dollars): $78.6 million per unit (SCE), $21

million per unit (SDG&E), $3.3 million per unit

(City of Anaheim), and $1.9 million (City of

Riverside). In sum, these shares amount to almost

$105 million (1986 dollars) per unit.

The California PUC has authorized SCE to

collect $620 million (1992 dollars) for decommissioning costs (based on a site-specific cost

estimate). As mentioned earlier, SCE is required

to return the site to ‘‘beach sand” condition after

operation, because the SONGS units are on

Federal land. Therefore, the decommissioning.

cost estimate is significantly greater than the

NRC-mandated minimum, which considers reactorblock decommissioning only. SCE is currently

depositing $18 million per year into its external

trust. To date, the utility has collected $375

million. No revision of the estimated decommissioning cost has been made since the decision to

shutdown Unit 1, and no formal evaluation has

been performed to evaluate the decommissioning.

potential impacts on from either premature retirement or license renewal of Units 2 and 3.
Index

Accident risk, 5, 12,65,67-69,80

Accident Sequence Precursor program, 69

ACE. See Atlantic City Electric Company

ACRS. See Advisory Committee on Reactor Safeguards

Administrative Procedures Act, 13,45

Advisory Committee on Reactor Safeguards, 19,68

AEA. See Atomic Energy Act of 1954

AEC. See Atomic Energy Commission

Age-related degradation unique to license renewal, 16-17,

18,58-59

Aging.

causes and effects, 3744

effects on cost and performance, 93

experience with, 6-9

degradation 9, 37

federal safety policy considerations, 6, 17-20

impact of aging on safety goals, 64-69

institutional efforts, 11-13, 44-47

license expiration and renewal, 13-17,57-59,61

management of, 10,47-57

maintenance practices, 49-52

mechanisms for metals, 38

nuclear power plant design, 48-49

occupational health impacts, 69-71

overview, 10-11

public health goals, 61,63-64

research, 52-53, 55-57

ALARA. See As low as is reasonably achievable

American Nuclear Insurers, 145

American Society of Mechanical Engineers, 39-40, 48,49,

162

ANI. See American Nuclear Insurers

Annealing, reactor pressure vessel embrittlement and, 40

ARDUTLR. See Age-related degradation unique to license

renewal

As low as is reasonably achievable, 64, 140

ASME. See American Society of Mechanical Engineers

Atlantic City Electric Company, 156, 165

Atomic Energy kt of 1954, 11,44,57

Atomic Energy Conum“ssion, 48, 84, 170

Atomic Industrial Forum, 135

Babcock and Wilcox, 16, 149

Babcock and Wilcox Owners’ Group, 16

Backfitting rule, 59,61

Background radiation, 64-65, 107

Baltimore Gas and Electric Company, See Calvert Cliffs

Nuclear Power Plants

Below regulatory concern, 32, 103, 104-105

BG&E. See Baltimore Gas and Electric Company

Boiling water reactors

collective radiation doses, 139-141

cost estimates from decomissioning, 137-138

low-level waste, 109, 111

recirculation piping aging, 53-54

BRC. See Below regulatory concern

BWOG. See Babcock and Wilcox Owners’ Group

BWRS. See Boiling water reactors

CAAA. See Clean Air Act Amendments of 1990

Cables. See Electrical equipment

California Public Utilities Commission, 3,26,84,85, 171

Calvert Cliffs Nuclear Power Plants, 39

decommissioning, 156

life attainment and license renewal, 153-155

performance and operating history, 150-153

spent fuel storage, 98

Cancer mortality rates, 65,70-71

Capacity factors, 84-88,89

Capacity margins, 76

Capital additions, 25,89-91

Carbon dioxide emissions, 22,79

Case studies

Ca.lvert Cliffs site, 150-156

Hope Creek site, 156-160

Monticello site, 160-164

Salem site, 165-170

San Onofk site, 170-178

CFS. See Capacity factors

Chemical decontamination, 95, 129

Chernobyl nuclear accident, 67

CLB. See Current licensing basis

I 179
180 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Clean Air Act Amendments of 1990,80

climate change. See Global climate change

Collective radiation doses, 139-141

Colorado Public Utilities Comrnission, 84, 123

Combustion Engineering, 149-150

Commonwealth Edison Company, 75,89

ConEd. See Consolidated Edison Company of New York

Conflation Baseline Documentation Project, 158-159,

167

Consolidated Edison Company of New York, 95

Corrosion deftition, 38

Critical Mass Energy Pro~ct, 147

Current licensing basis, 11,58

DBD. See DesQn Bases Documentation Program

D&D. Decontamination anddecommissioning See Decommissioning

Decot isioning

cost estimation, 132-139

decontamination and decomissioning, 127, 129-130

deftition, 101

dismantlement technologies, 130, 132, 133

early retirement financial requirements, 141-147

federal policy considerations, 6,33-36

financing, 33, 128-129

international experience, 125, 127, 130

overview, 30-31

radiation exposure estimation, 132, 134, 139-141

radioactive waste disposal, 108-118

residual radioactivity standards, 31-33, 102-108

U.S. experience, 118-125

DECON, 32, 101, 112, 122, 134, 137, 139-14095

Decentarnination factor, 127, 129

Delmarva Power and Light, 165

Demand-side management, 76-77

Design Bases Documentation Program, 173, 175

DF. See Decontamination factor

Division of Ratepayer Advocates, 3,84

DLC. See Duquesne Light Company

DOE. See U.S. Department of Energy

DP&L. See Delrnarva Power and Light

DW. See Division of Ratepayer Advocates

DSM. See Demand-side management

Duke Power Company, 42

Duquesne Light Company, 120

Early retirements. See also Decomrnissioning

recent plant closures, 3-4

Economic incentive programs, 84-86

Economic issues

aging issues, 24-25

changing electric utility context, 73-81

factors affecting future costs, 92-99

federal policy considerations, 6,27-30

institutional roles, 26-27, 81-86

overview, 24

performance of existing plants, 86-92

prospects for existing plants, 20-24

EDF. See Electricity de France

EDG. See Emergency diesel generator

EDO. See Executive Director for Operations

EIA. See Energy Information Adrmru“ “stration project

Electric Power Research Institute, 29,44-45,52, 81

Electric industry competition,76-79

Electricity demand and capacity margins, 75-77

Electrical equipment, 10,57,62

Electricity de France, 51

Embrittlement

deftition, 38

reactor pressure vessels and, 3940

Emergency diesel generator, 39,51

Energy Information Administration 76

Energy Policy Act of 1992, 29, 78,82, 105

enhanced participatory rulemaking, residual radioactivity

standards and, 32, 104-106

ENTOMB, 32-33, 34-35, 101-102, 112, 142

Environmental issues, 22,79-81

Environmental qualification of electrical equipment, 10,57,

62, 162

Environmental Restoration and Waste Management program, 122, 125

EPA. See U.S. Environmental Protection Agency

EPA Standard: 40 CFR 192.12, 106

FPA Standard: 40 CFR Part 261, 116

EPACT. See Energy Policy Act of 1992

Epidemiological studies, 66

EPRI. See Electric Power Research Institute

EQ. See Environmental qualification of electrical equipment

Equipment forced outage rate, 60,61

ERWM. See Environmental Restoration and Waste Management program

Executive Director for Operations, 46

Fabrication defects, 38

Fatigue , 10,38,57

Federal Energy Regulatory Commission, 26, 171

Federal policy considerations

assuring adequate aging safety, 17-20

decomrnissioning, 33-36

overview, 6

supporting economic decisions, 27-30

FERC. See Federal Energy Regulatory Commission

Fitzpatrick Nuclear Power Plant, 75-76

Formally Utilized Sites Remedial Action Project, 122

Fort St. Vrain Nuclear Generating Station

decommissioning, 123-125

early retirement, 3, 8440 CFR 192,12. See EPA Standard:

40 CFR 192.1240 CFR Part 261, See EPA Standard:

40 CFR Part 261

Foster-Wheeler Energy Corporation, 124

FSD. See Full system decontamination

FSV, See Fort St. Vrain Nuclear Generating Station

FI’OL. See Full-term Operating License

Fuel costs, 91-92

Full system decentamination, 95

FUSRAP. See Formally Utilized Sites Remedial Action

Project

General Atomics Technologies, 84

“General Design Criteria for Nuclear Power Plants. ” See

NRc

Standard: 10 CFR Part 50, Appendix A

General Electric, 149-150

General Public Utilities Nuclear Corporation, 128
Index I 181

Generic Safety Issues, 17, 57

Global climate change, 22,79

GPU. See General Public Utilities Nuclear Corporation

Greater-than-Class C, 111

GSIS. See Generic Safety Issues

GTCC. See Greater-than-Class C

High-level waste. See Spent fuel disposal

Historical capital costs, 88-89

Hope Creek site

decommissioning, 159

life attainment and license renewal, 158-159

performance and operating history, 156-158

Hydropower, 81

IAEA. See International Atomic Energy Agency

ICC. See Illinois Commerce Commission

ICRP. See International Commission on Radiological

Protection

Idaho, 124

Idaho National Engineering Laboratory, 124

IEEE. See Institute of Electrical and Electronics Engineers

IGSCC. See Intergranular stress corrosion cracking

Illinois Commerce Commission, 89

Important to license renewal components, 58, 153

Important to power production components, 153

Independent spent fuel storage installations, 28,98, 155

Individual plant examinations, 68

Industrywide Initiative, 81,96

INEL. See Idaho National Engineering Laboratory

INPO. See Institute of Nuclear Power Operations

Inspections, 57

Institute of Electrical and Electronics Engirwrs, 62, 162

Institute of Nuclear Power Operations

description, 45

evaluations of operating plants, 53, 57

maintenance guidelines, 49-50

quantitative indicators of nuclear performance, 60

Integrated plant assessment, 16,59

Integrated resource planning, 21, 82-83

Intergranular stress corrosion cracking, 38, 152

Intemational Atomic Energy Agency, 6, 103

International Commission on Radiological Protection, 70

LPA. See Integrated plant assessment

IPEs. See Individual plant examin ations

IRP. See Integrated resource planning

ISFSIS. See Independent spent fuel storage installations

ITLR. See Important to license renewal components

ITPP. See Important to power production components

LCMDATA. See Life-cycle management data

Uast-cost planning. See Integrated resource planning

LERs. See Licensee event reports

License renewal

aging management, 57-59, 61

and aging safety, 13-17, 18-19

License termination, 142-143

Licensee event reports, 60, 152

Life-cycle management data, 155

Life-cycle management programs, 6, 8, 153, 167

LILCO. See Long Island Lighting Company

LIPA. See Lmng Island Power Authority

LLRWPA, See Low-Level Radioactive Waste Policy Act

LLRWPAA, See ~w-hvel Radioactive Waste Policy

Amendments Act of 1985

LLW. See Low-level waste

Long Island Lighting Company, 3, 126

Ixmg Island Power Authority, 127

Low-Level Radioactive Waste Policy Act, 108-109, 113

~w-~vel Radioactive Waste Policy Amendments Act of

1985, 104, 108-109, 113

~w-level waste

disposal, 96-99, 108-112

mixed waste, 35, 116-117

projected volumes, 112-116

regulatory policies, 35-36

MAELU. See Mutual Atomic Energy Liability Underwriters

Maintenance rule, 10, 18,49

Maintenance Tarn Inspections, 57

Mechanical effects of metal aging, 38

Metals degradation, 38

Minnesota, 23, 98, 164

Minnesota Public Service Commission, 98

Mixed waste. See Imw-level waste

Monitored retrievable storage facility, 23, 28, 97

Monticello Nuclear Power Plant

decommissioning, 164

life attainment and license renewal, 14, 59, 161-164

performance and operating history, 160-161

MRS. See Monitored retrievable storage facility

Mutual Atomic Energy Liability Underwriters, 145

National Energy Strategy, 21

National Environmental Policy Act, 14

National Research Council, 29

NDE. See Nondestructive examination methods

NDTs. See Nuclear decommissioning trusts

NEIL. See Nuclear Electric Insurance Limited

NERC. See North American Electric Reliability Council

New Jersey, 160

New York, 3, 82

New York Power Authority, 75-76

Niagara Mohawk, 94

Nitrogen oxide, 80

Nondestructive examination methods, 40,51

North American Electric Reliability Council, 74

North Anna Nuclear Power Plant, 88,94

Northern States Power Company, 23, 98, 160-164. See also

Monticello Nuclear Power Plant

NPAR program. See Nuclear Plant Aging Research program

NRC. See U.S. Nuclear Regulatory Commission

NRC Regulatory Guide 1.86, 142

NRC Standard: 10 CFR 50.2, 106

NRC Standard: 10 CFR 50.46, 142

NRC Standard: 10 CFR 50.49, 162

NRC Standard: 10 CFR 50.55a(g), 142

NRC Standard: 10 CFR 50.75, 144, 146

NRC Standard: 10 CFR 60.61, 142

NRC Standard: 10 CFR 61.50, 115

NRC Standard: 10 CFR Part 50, Appendix A, 48, 58

NRC Standard: 10 CFR Part 50.75, 126

NSP. See Northern States Power Company

Nuclear decommissioning trusts, 147
182 I Aging Nuclear Power Plants: Managing Plant Life and Decommissioning

Nuclear Electric Insurance Limited, 145

Nuclear Maintenance Applications Center, 52

Nuclear Management and Resources Council, 13,44-45, 81

Nuclear Plant Aging Research program, 20,53,55-57

Nuclear power plants. See also Aging

challenges to industry, 1-2

costs, 86-92

design and aging, 4849

external review of activities, 53, 57

license expirations, 15

locations, 6, 7

policy issues, 2-6

Nuclear Waste Fund, 23,97

Nuclear Waste Policy Act of 1982, 23,28,96-97

Nuclear Waste Technical Review Board, 97

NUMARC. See Nuclear Management and Resources

council

NWF. See Nuclear Waste Fund

NWPA. See Nuclear Waste Policy Act

NYPA. See New York Power Authority

Occupational health, 69-71, 140-141

Office of Civilian Radioactive Waste Management, 97

O&M. See Operation and maintenance costs

~ration ~d rnaintmance COsts, 24,91-92

Organization of Economic Cooperation and Development, 6

Other radioactive waste, 110

PacYlc Gas and Electric Company, 85

PDMS, See Post defueling monitored storage

Pennsylvania State I_nw-hvel Waste Advisory Commission, 20

Performance indicators

Calvert Cliffs site, 152

description, 60

Hope Creek she, 158

Monticello she, 161

Salem she, 167

San Onofre site, 173

PGE. See Portland General Electric

PG&E. See PacKlc Gas and Electric Company

Philadelphia Electric Company, 94, 127, 165

PNM. See Public Service of New Mexico

POL. See Possession-only license

Portland General Electric, 4, 82-83, 129

Possession-only license, 142

Post-closure costs, 144

Post defueling monitored storage, 128

PRA. See Probabilistic risk assessment

Prepayment, 146

Pressurized thermal shock, 38

Pressurized water reactors

collective radiation doses, 139-140

cost estimates from decommissioning, 137

low-level waste, 109, 111

steam generators, 42-43

Price Anderson Act, 80, 123

Probabilistic risk assessment, 50-51,68-69

Production costs, 91-92

PSCO. See Public Service of Colorado

PSE&G. See Public Service Electric and Gas Company

PTS. See Pressurized thermal shock

Public Citizen, 147

Public health, 61,63-64

Public opinion, 5, 45-46. See also Enhanced participatory

n.demaking

Public radiation doses, 64-66

Public Se~ice Electric and Gas Company, 85, 156-160,

165-170

Public Service Company of Colorado, 3,23,84, 123

Public Service Company of New Mexico, 89

Public utility cornrnissions, 26, 82, 83, 144

Public Utility Regulatory Policies Act of 1978,78

PUCS. See Public utilhy commissions

PURPA. See Public Utility Regulatory Policies Act of 1978

PWRS. See Pressurized water xeactors

Radiation doses

estimating for decommissioning, 139-141

nuclear power plant workers, 69-71, 140-141

public, 64-66

Radioactive waste. See I_nw-level waste; Spent fuel disposal

Rancho Seco Nuclear Power Plant

early retirement, 3

fiiancing decommissioning, 128

RCM. See Reliability-centered maintenance

Reactor pressure vessels, 38-40

Recirculation piping, 53-54

Reference reactors, 137-141

Reliability-centered maintenance, 50

Residual radioactivity standards, 31,32, 102-108

Resource Conservation and Recovery Act of 1976,35

Restricted use, 32, 107

Retirement. See Decommis sioning; Early retirement

RFM. See Risk-focused maintenance

Risk assessment, 66-67

Risk-focused maintenance, 50-51

Robotics, 51

RPVS. See Reactor pressure vessels

Sacramento Municipal Utility District, 3, 128

Safety goal policy, 12,20, 63-64

SAFSTOR, 32, 177-178

Salem site

decommissioning, 169-170

life attainrnent and license renewal, 167-169

performance and operating histoxy, 165-167

spent fiel storage, 169

SALP. See Systematic assessment of licensee performance

San Diego Gas and Electric Company, 84, 170

San Onofre Nuclear Generating Station

decommissioning, 175-178

early retirement, 3-4, 84

financing decommissioning, 128

life attainment and license renewal, 172-175

performance and operating history, 170-172

Sandia National Laboratories, 62

SCE. See Southern California Edison Company

Scrams, 60, 61

SDMP. See Site Decommissioning Management Plan program

SEP. See Systematic Evaluation Progmtn

SGS. See Steam generato~

Shippingport Nuclear Power Plant, 120-122
Index I 183

Shoreham Nuclear Power Plant

decommissioning, 126-127

early retirement, 3

Site Decommissioning Management Plan program, 122

SMUD. See Sacramento Municipal Utility District

SOC. See Statement of considerations

SONGS, See San Onofre Nuclear Generating Station

Southern California Edison Company, 3, 84, 170-178

Spent fuel disposal, 23, 27-28, 96-99, 117-118

SSCS. See Systems, structures, and components

Staffing, 91-92

Standard Review Plan, 48

Statement of considerations, 16, 59

Steam Generator Replacement Group, 42

Steam generators, 42-43

Sulfur dioxide, 80

Surety method, 146

Systematic assessment of licensee performance

Calvert Cliffs site, 154

description, 24,60

Hope Creek site, 157

Monticello site, 163

Salem site, 168

San Ormfre site, 174

Systematic Evaluation Program, 10,49

Systems, structures, and components, 37-44

10 CFR 50.2. See NRC Standard: 10 CFR 50.2

10 CFR 50.46. See NRC Standard: 10 CFR 50.46

10 CFR 50.49. See NRC Standard: 10 CFR 50.49

10 CFR 50.55a(g). See NRC Standard: 10 CFR 50.55a(g)

10 CFR 50.75. See NRC Standard: 10 CFR 50.75

10 CFR 60.61. See NRC Standard: 10 CFR 60.61

10 CFR 61.50. See NRC Standard: 10 CFR 61.50

10 CFR Part 50, Appendix A. See NRC Standard: 10 CFR

Part 50, Appendix A

10 CFR Part 50.75. See NRC Standard: 10 CFR Part 50.75

Three Mile Island, 65, 67, 128

TLG Services, Inc., 159

TMI. See Three Mile Island

Trojan Nuclear Power Plant

early retirement, 4

economic analysis, 82-83

fiiancing decommissioning, 129

Union of Concerned Scientists, 47

Unit cost factor, 135

Unrestricted use, 106-107

U.S. Department of Energy

aging research, 52-53

Shippingpofi decornmissioning, 120-122

spent fuel disposal, 23, 96-97

U.S. Environmental Protection Agency, 35, 105

U.S. Nuclear Regulato~ Commission

aging research, 52-53, 55-57

assuring adequate aging safety, 17-20

enhanced participatory rulemaking, 32, 104-106

inspection program, 57

license renewal rule, 13-14, 16,58-59

licensee financial conditions rule, 33

maintenance rule, 10, 49

public participation in, 19, 20,31-32,45,47

safety goal policy, 12, 63-64

Virginia Power, 88, 94

Washington Public Power Supply System, 94

Waste disposal. See Low-level waste; Spent fuel disposal

Westinghouse Electric Corporation, 123, 149-150

Workers. See Occupational health

YAEC. See Yankee Atomic Electric Company

Yankee Atomic Electric Company, 47, 128

Yankee Rowe Nuclear Power Plant

early retirement, 3, 75

financing decommissioning, 128

license renewal request, 14, 16

public petition, 47