COVER:
A heat-sensitive DOE photograph of Three Mile Island taken on the eighth day of the accident. Yellow areas
are at a higher temperature.

Available fromGPO Sales Program
Division of Technical Information and Document Control
U.S. Nuclear Regulatory Commission
Washington, D.C. 20555
andNational Technical Information Service
Springfield, Virginia 22161

II
three
mile
islandVOLUMEPart IA REPORT TO THE
COMMISSIONERSAND TO THE
PUBLICMITCHELL ROGOVIN
director

GEORGE T. FRAMPTON, JR.
deputy director
NUCLEAR REGULATORY COMMISSION
SPECIAL IN QUIRY GROUPFOREWORD
This is the second volume of the Special Inquiry Group's report to the Nuclear
Regulatory Commission on the accident at Three Mile Island. The first volumecontained a narrative description of the accident and a discussion of the major
conclusions and recommendations.
This second volume is divided into three parts. Part 1 of Volume II focuses on
the preaccident licensing and regulatory background. This part includes an examination of the overall licensing and regulatory system for nuclear powerplants
viewed from different perspectives: the system as it is set forth in statutes andregulations, as described in Congressional testimony, and an overview of the system as it really works. In addition, Part 1 includes the licensing, operating, andi nspection history of Three Mile Island Unit 2, discussions of relevant regulatory
matters, a discussion of specific precursor events related to the accident, a casestudy of the pressurizer design issue, and an analysis of incentives to declarecommercial operation.
Part 2 of Volume II focuses on a technical description of the accident. It
includes a narrative description of the accident, a time line chronology, a discussion of radioactive releases and the radiation protection program at TMI, anassessment of plant behavior, a discussion of core damage and alternative
accident scenarios, and a discussion of human factors. Much of this work relies
on technical analyses performed by companies and organizations under contract
to the NRC and under the direct supervision of the Special Inquiry Group.
Sandia Laboratories conducted an analysis of the early parts of the accident
sequence, emphasizing thermal-hydraulics, chemical properties of the core, andi nterpretation of possible scenarios. Battelle Columbus Laboratories conducted ananalysis of the first 16 hours focusing on alternative scenarios as well as the actual
sequence. Los Alamos Scientific Laboratory and Idaho National Engineering Labs
provided analysis of reactor system behavior using advanced engineering codes.
These contracts were carried out under the joint direction of the NRC's Office of
Nuclear Regulatory Research and the Special Inquiry Group staff. The section on
Human Factors draws substantially from work performed by the Essex Corporation under contract to the NRC and monitored directly by the Special Inquiry
Group. Part 2 also contains an assessment of the environmental andsocioeconomic impacts of the accident. This analysis is based in large part onwork done by Mountain West Research, Inc., under contract to the NRC.
Part 3 of Volume II contains descriptions and assessments of responses to theaccident by (1) the utility, (2) the NRC, and (3) State and Federal agencies; ananalysis of information provided to the media during the accident; and a study
prepared for the Special Inquiry Group on safety management factors germane tothe accident. These sections contain considerable amounts of overlapping
material. However, the added emphasis is necessary to gain insight from the individual organizational focus. Part 3 also considers analyses performed under contract by the National Academy of Public Administration which provided an evaluation of organizational alternatives for crisis management.
Part 3 also contains an appendix that compares the recommendations made by
the Special Inquiry Group in Volume I of this report with recommendations madeby the President's Commission and by the NRR/NRC Lessons Learned Task
Force.
An index for all three parts of Volume II is contained at the back of Part 3.
Although the bulk of these in-depth studies was prepared by the staff of theSpecial Inquiry Group, as in the case of Volume I, we must take final responsibility
for the contents of this volume, and particularly for the conclusions and recommendations.

Mitchell Rogovin, Director
NRC/TMI Special Inquiry Group
George T. Frampton, Jr., Deputy Director
NRC/TMI Special Inquiry Group
January 1980

iv

AVAILABILITY OF
REFERENCES
The documents cited in this volume are primarilyof four types:

The NRC documents cited in this volume that areavailable in the PDR consist of the following:

1. NRC-originated material or material presented toor developed for the NRC
2. Material developed by or for other Federal andState bodies
3. Open literature publications consisting of copyrighted books, magazine articles, newspaper clippings, national and society standards, and othersociety publications (transactions, conference
proceedings, reports, etc.)
4. Publications of the United Nations

1.

2.
3.
4.
5.
6.

The NRC-originated material and that presented
to or developed for the NRC has been placed in the
NRC Public Document Room (PDR) at 1717 H Street,
N.W., Washington, DC. It is available for inspection
and for copying for a fee. Orders may be placed inperson, by mail or by telephone. Both paper copy
and microfiche can be purchased. Paper copy is 8
cents per page for standard size paper (8 X 11 1/2
inches) and 11 cents per page for larger size paper(drawings and foldouts). Microfiche copies are 25
cents per diazo duplicate. A minimum charge of$2.00 plus postage is made for mail orders. Whenordering by telephone or mail, acknowledge a willingness to assume charges for all orders but do notsend payment. Orders will be processed andmailed with a bill from the PDR contractor for thisservice. The telephone is (202) 634-3274 and theaddress is
NRC Public Document Room

7.
8.

9.
10.

11.
12.
13.
14.

1717 H Street, N.W.
Washington, DC 20555

V

Dispositions (both those taken by the
President's Commission and those taken by
the Special Inquiry Group. These are indicated by name and page number.)
Memorandums and letters (internal, external
and those received by NRC and others)
I nterviews (These are indicated by name andpage number.)
Regulatory Guides
Standard Review Plan (NUREG-75/087)
Technical Specifications (generic or docket
specific)
SECY papers (NRC staff papers for Commission consideration)
Commission Issuances (labeled, for example,
4 AEC 768, 6 NRC 1218, where "4" is thevolume number, "AEC" indicates pre 1975
i ssuances, "NRC" is post 1975, and "768" isthe page number. These issuances present
Commission opinions and decisions.)
ACRS transcripts and reports (Advisory Committee on Reactor Safety)
Docket material (for example, Docket 50-320
i s Three Mile Island 2. A Docket 50 file contains all materials pertinent to a specificpowerplant.)
Branch technical positions (from Office of
Nuclear Reactor Regulation)
NRC contracts (for example, NRC-05-77-044)
NRC Inspection and Enforcement Manual
Commissioner speeches

15.
16.
17.
18.
19.
20.
21.
22.
23.
24.
25.
26.
27.
28.

Public Announcements
Board Notifications (to ASLB and participants
i n proceedings)
Transcripts of Operating License Hearings (inDocket Files)
Operating licenses and amendments (inDocket files)
NRC Management Directives (that is, Manual
Chapters)
Transcripts of NRC Commission meetings
Proceedings of Atomic Safety and Licensing
BoardsIE Circulars and Preliminary Notifications (PN)
Vendor and licensee topical reports (for example, B&W, Met Ed, and GPU reports)
NRC Inspection Reports
Meeting summaries
Plant logs, charts, data
Reference foreign documents
NUREG and NUREG/CR series reports

Congressional hearings
General Accounting Office (GAO) reports
Senate reports (S. Rep.)
Congressional Reports (Cong. Rep.)
House reports (H. Rep.)
ERDA reports
DOE reports
Federal Energy Regulatory Commission (FERC)
Dockets
I nternal Revenue Service Ruling and Bulletins(com. Bul and Rev. Rul.)
Military Specifications (Mil. Spec.)
HEW reports
National Academy of Science reports
National Council on Radiation Protection(NCRP) reports
National Laboratory Reports (Savannah River
Laboratory, Lawrence Livermore Laboratory)
EPA Manual of Protective Action Guides
Federal Response Plan for Peacetime
Nuclear Emergencies
Federal Aviation Administration
U.S. Department of LaborWASH reports (WASH-1400 and others)

Some formal NRC reports, which are listed as
NUREG-XXXX or NUREG/CR-XXXX, may be purchased over the counter at the PDR. Reports notavailable at the PDR and NRC Regulatory Guides
are best obtained by those who have deposit
accounts with the Superintendent of Documents,
U.S. Government Printing Office, by calling (301)492-7333 or writing:
Attn:

State
D.C. Circuit Court (D.C. Cir.)
Pennsylvania Consolidated Statutes( Penn. Consol. Stat.)
Pennsylvania Supreme Court (Pa. Super. Ct.)
Pennsylvania Public Utilities Commission(PaPUC) hearings and proceedings
New Jersey Board of Public Utility
Commissioners
Pennsylvania-New Jersey-Maryland (PJM)
I nterconnection Agreement
Ohio Public Utilities Commission(Ohio PUC) hearings
Ohio Statutes (Ohio St.)
Pennsylvania Emergency Management Agency

Publications Sales Manager
Division of Technical Information andControlDocument
U.S. Nuclear Regulatory Commission
Washington, DC 20555

These documents may also be purchased fromthe National Technical Information Service (NTIS).
Either write to NTIS or call the Sales Desk at (703)557-4650. The address is
National Technical Information Service
Springfield, Va. 22161

The material developed by or for other Federal orState bodies is available from the organization citedor, in the case of reports prepared by other Federal
agencies, the documents are available for purchasefrom the U.S. Government Printing Office, theNational Technical Information Service, or the PublicDocument Room of the particular agency. The
documents cited in this volume that fall in thiscategory are the following:

The open literature publications cited may beavailable in public libraries and are, of course, available from the publisher. Documents of this type arealways copyrighted. Those cited in this volume include newspapers, books, journals, national and industry standards, and association and society transactions and reports.
The publications of the United Nations are available from that organization.

FederalActs of Congress (Public Laws)
Federal Registervi

CONTENTS
Forewordiii

Outline of Volume II, Parts 1, 2, and 3

xi

A.

Licensing and Regulation of Nuclear Powerplants

1

1. An Examination of NRC's Licensing and Regulatory System for Nuclear
Powerplants from Different Perspectives

1

Availability of Referencesva. The System as Established in Applicable Statutes and Regulations
b. The NRC Assessment of the Basis for Reactor Safetyc. The Licensing and Regulatory System for Nuclear Power Reactors: An
Overview of Its Major Deficiencies in Assessing Reactor Safety
d. Findings and Recommendations

2. Relevant Regulatory Staff Actions Taken Outside of the Adjudicatory
Processa. Issuance of Operating Licenseb. Amendments, Exemptions, and Modifications to the TM 1-2 License
c. Pending Regulatory Actions
d. Status of Pertinent Commitments to the Regulatory Staff
e. Findings

3. Other Relevant Mattersa. Regulatory Requirements Review Committeeb. Quality Assurancec. Generic Issues
d. Technical Qualifications

vii

2
7
11
23
30
30
30
34
34
36
38
38
44
50
55

B.

Licensing and Operating Histories

65

1. Licensing History of TMI-2

65

a. Introduction
b. Summary of Licensing Events-TM 1-2 and TM I-1
c. TMI-2 Construction Permit Review-May 1968 to November 1969
d. The Postconstruction Permit Review Period, 1969-74
e. The Operating License Review Period-January 1974 to February 1978...
f . Findings and Recommendations

2. Operating History of Three Mile Island Nuclear Station
3. Inspection History at Three Mile Island (TMI) Site
C. Precursor Events

108

117
129

1. Overview and General Description

129

3. Relevance of Precursor Events

138

2. Conclusions and Recommendations

130

4. Depositions

138

6. Beznau Incident-August 20, 1974

140

139

5. Dopchie Letter-April 27, 1971

7. Reactor Safety Study (WASH-1400)-October 1975

8. Michelson Report-September 1977
9. Davis Besse-September 24, 1977

10. Kelly-Dunn Memoranda-November 1, 1977

11. Pebble Springs ACRS Questions-November 1977
12. Creswell Concerns-December 1977

13. Israel-Novak Note-January 10, 1978

14. Rancho Seco Incident-March 20, 1978

15. Three Mile Island-March 29, 1978/Sternberg Memorandum-March 31,
1978
D.

65
66
67
77
81
1 04

Pressurizer Design and Performance: A Case Study

E. Incentives to Begin "Commercial Operation...
1. Introduction and Conclusions

2. Incentives for Completing All Work at TMI-2 Before the End of 1978

a. Rate Recognition of TMI-2
b. Tax Ramification of Placing TM 1-2 in Commercial Operation in 1978
c. Other Financial and Nonfinancial Incentives

3. Actions Taken at TMI-2 Indicating Time Considerations That Were Linked
to Financial Incentives

142
144

149
157
161

164

172
173
175
183
203
203
204

204
212
216
222

4. It Cannot Be Concluded That the Action Taken to Enable Completion of
TMI-2 in 1978 Compromised the Safety of the Unit

232

6. Recommendations

241

5. Implications

VIII

235

Appendices
1.1

The Statutory Origin of the NRC's Organizational Structure

1.3

Plant Designs Licensed to Operate Using B&W Nuclear Steam Systems

1.2 Agreed-Upon Division of Responsibility Between NRR and IE Where Their
Functions Interface
1.4

Licensing Organization, 1969 to 1979

1.5 The Standard Review Plan

269
273
274
281

1.6 ACRS Letter-October 22, 1976
1.7

261

Extracts from Adjudicatory Decisions-Three Mile Island Nuclear Station
Unit 2

ix

283
287

OUTLINE OF VOLUME II
PARTS 1,2,AND3

Part 1

Foreword
I.

Preaccident Licensing and Regulation Background

A. Licensing and Regulation of Nuclear Powerplants
B. Licensing and Operating Histories
C. Precursor Events

D. Pressurizer Design and Performance-A Case Study
E. Incentives to Declare Commercial Operation
Part 2

II. The Accident and Its Analysis

A. Accident Chronology (Narrative Sequence of Events)
B. Radiological Releases

C. Plant Behavior and Core Damage
D. Alternative Accident Sequences
E. Human Factors

F. Environmental and Socioeconomic Impacts
Part 3Ill. Response to the Accident
A. Utility Response
B. NRC Response

C. Response of State and Federal Agencies (Except NRC)
D. News Media Interface at Three Mile Island

xi

IV.

Safety Management Factors Germane to the Accident
1.

I ntroduction

3.

NRC Safety Policy

2.
4.

5.

Statutory Considerations
Safety Planning

Requirements and Enforcement

6.

Safety Tasks

8.

Conclusions and Recommendations

7.

9.

Organization for Safety
Epilogue

V.

List of Depositions Taken

VI.

Comparison of the Special Inquiry Group Recommendations Contained inVolume I with Those of the President's Commission and the NRR-NRC
Lessons Learned Task Force
I ntroduction

Identification of Recommendations by Subject Area
Findings and Recommendations in Volume II

I ndexxii

I. PREACCIDENT LICENSING
AND REGULATIONBACKGROUND

A LICENSING AND
REGULATION OF
NUCLEAR
POWERPLANTS
i dentifying the major actors in the regulatory process and the roles they play. Next, "TheCommission's Assessment of the Basis for Reactor
Safety" sets forth a portion of the remarks of former
NRC Chairman Joseph Hendrie before a Congressional oversight committee in February 1979. As
such, it constitutes the most contemporaneous publi c self-assessment of the operation of the regulatory process at the time of the accident at Three Mile
Island. Finally, "The Licensing and Regulation System for Nuclear Powerplants: An Overview of Its
Major Deficiencies in Assessing Reactor Safety"
describes the major shortcomings in the present regulatory process.
Each of these perspectives provides different insights into the existing regulatory process governing
the construction and operation of nuclear powerplants. Each contributes to an understanding of thecontext of the accident at TMI-2 and of the recommendations made elsewhere in this report.

1. AN EXAMINATION OF THE NRC'S
LICENSING AND REGULATORY SYSTEM FOR
NUCLEAR POWERPLANTS FROM DIFFERENTPERSPECTIVES
Frequently many diverse perspectives contributeto a complete understanding of a particular
phenomenon. The following three sections set forthdifferent perspectives of how the regulatory processadministered by the Nuclear Regulatory Commission
attempts to ensure that nuclear powerplants areconstructed and operated safely, and how effectivel y the Commission performs its functions.
The first section, "The System as Established in
Applicable Statutes and Regulations," provides an
overview of the licensing and regulatory process,setting forth the major substantive and procedural
requirements for obtaining NRC authorization to
construct and operate a nuclear powerplant and1gineering goals" rather than "precise tests or
methodologies by which reactor safety can be fully
9. . . gauged." The General Design Criteria are supI ntroduction
plemented by the staff's Standard Review Plan andRegulatory Guides, which set forth a description of
Many parties share responsibility for the safe
the staff's internal standards for measuring complidesign, construction and operation of nuclear
ance with the GDC. However, neither the Standard
powerplants. The Nuclear Regulatory Commission's
Review Plan nor the Regulatory Guides are embofunction is to set standards for radiological safety,
died in NRC regulations. Thus, although complianceenvironmental protection, and antitrust conformity'with these interpretive materials generally can bewhich the applicant must satisfy to obtain a license,
expected to facilitate staff approval, they are not,and to ensure the utility's subsequent compliancestrictly speaking, mandatory, and applicants are freewith those standards through audit-type inspections
to select other methods for complying with the Genand other enforcement activities. The Commission
must coordinate its activities with other Federaleral Design Criteria.
agencies which dictate environmental and healthAs part of its application for a construction permit, the utility must submit a Preliminary Safety
standards that the licensee must meet, and with
Analysis Report (PSAR). 10 The PSAR must contain
State and local governments having regulatory overi nformation on the site and its suitability for the prosight for nonradiological matters in plant siting, conposed unit; a summary of the facility itself, including
struction, and operation.
safety considerations; preliminary design information
Although the NRC has plenary regulatory responsibility over all matters of radiological health and related to the NRC's General Design Criteria; theQuality Assurance Program planned to meet NRCsafety, the primary responsibility for the safe design,
established requirements;" an assessment of theconstruction, and operation of a nuclear powerplantrisks of the plant's operation to the public; identifiunder the present regulatory system ultimately rests
cation of additional research into safety issues
with the utility. 2 This division of responsibility isnecessary before the design can be granted an
perhaps best illustrated by analyzing the NRC
operating license; an emergency plan to cope withli censing process.
emergencies; and the technical and financial qualification of the utility to build and operate the facility.
The Licensing Process
In addition, the applicant must submit information to
the NRC on the impact the nuclear plant will have on
The NRC uses a two-step licensing approach, inthe environment; 12 and must advise the Attorney
volving a safety evaluation and mandatory hearing
General of any anticompetitive impact that wouldbeprior to the issuance of a construction permit and13
created or maintained by grant of the license.
another complete safety evaluation and a nonmanThis information allows the NRC staff to evaluate
datory hearing prior to the issuance of an operating
the design of the plant, environmental impact thatlicense.3 This two-step process requires issuancemight be presented by its operation, and anyof a construction permit before major work can begin on a nuclear facility and, thereafter, the grant ofrelevant antitrust problems. Following a radiologicalsafety review, the staff prepares a Safety Evaluation
an operating license before the unit can actually beReport. 14 This report provides the basis for safety
gin producing power with nuclear fuel.
findings by the staff and identifies problems the NRC
An applicant must submit information to the NRC
at each stage of licensing proceedings. The Atomic
staff has with the proposed safety features andEnergy Act of 1954 prohibits construction on a nugeneral plant design. The staff also prepares aclear facility without the construction permit. 4-6 If
Draft Environmental Statement, which is circulated
construction is completed in accordance with thisfor comment, revised, and converted into a Final Enpreviously issued permit and the completed plantvironmental Impact Statement in accordance with
15
The Enmeets NRC standards, an operating license will be
the National Environmental Policy Act.
7
vironmental Statement describes the impact on thei ssued.
No specific nuclear powerplant design is required
environment that the proposed plant would have,measures alternatives and identifies resources thatby the NRC; the design submitted must only conform to the statutory and regulatory standards inwoula oe lost by construction.
order to obtain approval. The General Design CriIn addition, an analysis is made of the utility's
technical
and financial qualification to construct andteria (GDC) set forth minimum requirements for prinoperatetheplant. The Commission's review of
cipal design criteria found necessary in plants oftechnical
qualifications
involves an analysis of thesimilar design and location previously licensed by
8
utilities'
organizational
structure,including the depth
the Commission.
These criteria constitute "ena. The System as Established In Applicable
Statutes and Regulations2

of its engineering and nuclear expertise. The financial analysis constitutes an effort to determine if theutility can afford to safely construct, operate, anddecommission the plant at the end of its useful life.
The Atomic Energy Act requires a mandatory
public hearing regarding the construction permit. 16' 17
The decision whether to grant each application isdecided in an adjudicatory, evidentiary proceeding
before an Atomic Safety Licensing Board (ASLB), a
three-member panel consisting of an attorney servi ng as chairman and two technical members, which
has been delegated the responsibility and authorityof the Commission to make initial decisions regardi ng both construction permits and operating
licenses. The Commission staff appears in theseproceedings, even if they are uncontested, and theapplicant has the burden of proof.
The difference between an uncontested and contested construction permit hearing is significant. In
an uncontested hearing, the ASLB does not conduct
a de novo review of the application; it only decides
generally whether the staff's review of theapplicant's proposal was adequate. 18 I n a contested
proceeding, by contrast, the ASLB must resolve thespecific contentions raised by the parties concerni ng the application, although it has limited authority
to consider other matters not put in issue by theparties in "extraordinary circumstances" where it
determines that "a serious safety, environmental orcommon defense and security matter exists." 19 The
NRC staff assumes the role of a party; it is given no
special status or weight except as to discovery
matters.
A contested hearing occurs when either the staff
or intervenors oppose the grant of the license. Intervention can be granted to any person whose "interest may be affected." In addition, States or theirsubdivisions have a unique right of intervention
under NRC regulations. They are allowed to participate fully in the hearing, to cross-examine others
and present their own case, but are not required totake position on issues, as do other parties. Additionally, a person may make a "limited appearance"
at a hearing and thus be granted an opportunity toaddress the ASLB but not to cross-examine otherparties' witnesses. 20 No NRC regulation may be attacked by a party in either a construction permit oroperating license proceeding, except on a successful showing by petition for waiver or exemption, that"special circumstances with respect to the subject
matter of a particular proceeding are such that application of the rule or regulation ... would not serve
the purposes for which [it] was adopted ... "2t
The change in public participation in the ASLB
process is reflected by the dramatic increase in thepercentage of contested hearings. During the

1960s, hearings were rarely contested and the
ASLB's major function involved determinations regarding the quality of the staff's review. In the
1970s, by contrast, virtually every hearing has been
contested, and the ASLB's focus has centered almost exclusively
on the contested issues raised by22
the parties.
Decisions of the ASLB normally become final
Commission decisions unless appealed by a party.
Even if appealed, an ASLB decision becomes final
i mmediately unless an opposing party demonstrates
good cause why it should not. By delegatedauthority, the Atomic Safety and Licensing Appeal
Board is authorized to consider and resolve issues
appealed from the ASLB by parties to that proceedi ng. In "extraordinary circumstances," the appeal
board also may consider serious issues not raisedby the ASLB in an operating license proceeding.
The appeal board may certify major or novel questions of policy, l aw or procedure for theCommission's consideration. In addition, parties
may seek to appeal issues resolved by the appeal
board, and the Commission may, on its own motion,
review the appeal board's actions or decisions incases of exceptional importance. Commission
review is discretionary, however, 10 C.F.R.
2.786(b)(4), and appeal board23
determinations not so
reviewed are considered final.
Each application for a construction permit oroperating license must be submitted to the NRC's
24.17
Advisory Committee on Reactor Safety (ACRS).
The ACRS is a statutorily-created independentgroup of experts in fields relevant to reactor safety,
selected by the NRC to advise in reactor safety
matters. The committee's independent analysis of
the safety of each proposed plant is recorded in a
written letter to the NRC chairman. The ACRS
views are not entered into evidence for the substance of their contents-that is, reactor safetyconcerns-but for the more limited purpose ofdemonstrating compliance with the statutory
requirement that an advisory committee review has
been conducted. It is for the NRC staff, intervenors
or, in some cases, the Atomic Safety Licensing
Board to raise any safety issues regarding theapplication that might be identified in the advisorycommittee's report.
With the grant of the construction permit, theapplicant assumes the responsibility of informing the
NRC of any deficiencies it finds in the design orconstruction of the plant or in any breakdown in the
Quality Assurance Program required by Appendix Bof 10 C.F.R. Any change in the "principal architectural and engineering criteria" must be authorized byamendment to the construction permit, and an application for such an amendment must satisfy the3from the contested arena unless they are raised byan intervenor. As a result of this informal process,many potential "problems" are eliminated by consultation between the staff and applicant long before
the adjudicatory hearing process begins. Typically,
these issues never surface again at later stages ofthe licensing process.
Procedural mechanics aside, the standards usedby the NRC in determining whether to grant a construction permit or an operating license are different.3 The standards for issuing a construction
permit provide that the permit can be issued even
without all of the technical information that will eventually be necessary for an operating license if "theprincipal architectural and engineering criteria" havebeen described, further information will eventually
be supplied; research into safety issues is promised;
and there is "reasonable assurance" that all safety
considerations will be resolved before completion of
construction and that the proposed nuclear plant"can be constructed and operated at the proposedl ocation without
undue risk to the health and safety
30of the public."
The terms "reasonable assurance" and "unduerisk" are nowhere defined, either in the statute or in
the NRC's regulations, however. They are derived
from the basic health standards in that Act such as"adequate protection to the health and safety of the
public," no "unreasonable risk 28,31
to the health andsafety of the public," and the like.
There are built-in limitations in "converting" aconstruction permit to an operating license. For example, issuance of a construction permit normallydoes not indicate approval of safety systems unlesssuch approval has been specifically requested.
NRC regulations provide, however, that the Final
Safety Analysis Report must be submitted before an
operating license can be granted, and the operating
license is not granted unless the NRC is satisfied
that the safety systems are adequate. 32 An operati ng license will be issued if the plant was constructed in conformance with the construction permit application, the Atomic Energy Act, and theCommission's rules and regulations; if it will operate
i n conformance with all of the above; and, finally, if
there is reasonable assurance that the licensee's
activities will not endanger the health and safety ofthe public. The applicant also must show his technical and financial qualification to operate the nuclear
facility and must demonstrate that granting thelicense will not
be inimical to the common defense
33,34
and security.
The operating license is good for an initial periodof 40 years from the date the construction permit
was issued, subject to certain implicit conditions. 35

same procedural requirements and substantive
standards as previously described. Since "principal
architectural and engineering criteria" are nowhere
described in the regulations, however, identificationof the precise changes that might require anamendment to the construction permit calls for a
subjective judgment by the applicant and the NRC
25
staff.
At the operating license stage, the applicant must
update its Preliminary Safety Analysis Report bysubmitting a Final Safety Analysis Report (FSAR)
providing all information obtained regarding the site
since the construction permit application. The
FSAR must evaluate the results of the applicant's
research program to show that all safety questions
unresolved at the construction permit stage have
26
Additional information, including
been resolved.
applicant's proposed technical specifications defini ng the operational and safety limitations on theplant 27 must be provided. These technical specifications are a part of any license the NRC finallygrants, 28 and their violation is cause for enforcement action.
Unlike the construction permit review stage, there
is no requirement of a hearing prior to granting an
operating license. However, the NRC publishes notice of its intent to issue an operating license, andaffords the opportunity to anyone whose interest
may be affected to petition for intervention and request a hearing prior to issuing the license. If sucha petition is filed, and intervention granted, an adjudicatory hearing will be held. Appeals can be takenfrom these hearings, and such appeals proceed
through the same general appellate process as previously described. 29
The formal system discussed above is accompanied by a substantial amount of informal consultation between the NRC staff and the applicant. Fromthe earliest point of interest in obtaining a license,
an applicant may contact the staff to obtain guidance regarding methods of procedure and thecontent of required submissions. Frequently, thestaff will insist on changes in proposed designs orsiting features in order to write a favorable Safety
Evaluation Report or Environmental Impact Statement or to take other favorable action on an application. This informal negotiation process typicallycontinues throughout the application period. For
example, the staff amends the Safety Evaluation Report after its publication to include any "open" safetyi ssues, and it currently will not, as a matter of policy,
proceed to a licensing hearing without analyzing all
safety issues in that report. Informal resolution of
any such safety issues, and their removal from the
Safety Evaluation Report, removes these matters4

However, the NRC may revoke, suspend or amend
the license at any time during the 40-year
period . 36,37 The licensee is also subject to compliance with future38.39
rules and regulations which might
and the license is conditioned
be promulgated,upon having any operators licensed by the NRC atthe controls. 40 Just as the design of the plant system has to meet certain codes and standards
adopted by the NRC, so must performance of those41
systems meet adopted codes and standards.
Further, new technical specifications, rules and regulations and directives can modify the operation of
any specific unit.

health and safety or the environment. Briefly stated,
the NRC is responsible for determining that there is"reasonable assurance" that the applicant will comply with its regulations and that the health and safety of the public will not be endangered by the plant's
operation.
The NRC imposes substantial responsibilities ona utility when it becomes an applicant for a license
or a licensee. 44 Conditions on design, construction
and operation are imposed in the license or construction permit itself, as well as through the Technical Specifications. In spite of the formidable regulatory structure described above, the fact remainsthat the primary responsibility for the actual design,
construction and operation of a nuclear powerplantrests with the applicant-the utility that seeks to sell
the power to its customers. Finally, the utility has
the responsibility to properly decommission the nuclear facility. This includes filing and following an
NRC-approved decommissioning plan and terminati ng a license only with NRC approval.

I nspection and Enforcement
The NRC attempts to ensure compliance with thestandards it has set for the design, construction andoperation of the plant through inspection and enforcement. NRC regulations place a duty on the applicant to retain and make certain information available to the NRC Office of Inspection and Enforcement (IE). IE maintains regional inspection officesthat conduct announced and unannounced visits toplants to ensure compliance with the license,
Technical Specifications, the Atomic Energy Act,and the promulgated rules and regulations
thereunder. Some plants also have "resident" IE inspectors. Finally, when requested, the holder of aconstruction permit or an operating license mustalso undertake studies and make reports to the
NRC.42
Enforcement of these provisions is provided for inboth the Atomic Energy Act and in NRC regulations.
Sanctions include revocation, suspension or modification of a license, and the Commission is also authorized to seek injunctions in the Federal courts
and to impose civil penalties for violation of license
requirements. In appropriate cases, the directors of
the Office of Nuclear Reactor Regulation (NRR) andI nspection and Enforcement (IE) have the authority
to require immediate corrective action, subject tothe right of a licensee to challenge it later.4

Responsibilities of Nonlicensees

Generally, only licensees are legally responsible
to the NRC. Reactor system vendors, architectengineers and construction contractors are notli censed by the Commission. NRC regulations require, however, that each of these organizations report deficiencies in fabrication or construction of a
nuclear powerplant. 45 I n addition, the NRC's Quality
Assurance Program and the General Design Criteria
i mpose an element of indirect NRC control overthese nonlicensees. The reactor system vendors,architect-engineers and construction firms may also
have contractual responsibilities and may voluntarily
assume responsibilities beyond those required by
the Commission or other regulatory bodies.
The role of the reactor vendor is inextricably involved with NRC regulation, since no utility wouldpurchase a system that would not pass NRC scrutiny. Indeed, most applicants look to vendors forthe design material to be submitted to the NRC.
The vendors' designs conform with the GDC in part
because they have been modified in response topast staff evaluations of those systems in earlier
li censing proceedings.
Once an order has been placed with a vendor
and fabrication of the "basic components" begins,
the vendor becomes subject to the provisions of 10
C.F.R. Part 21. Part 21 is based on Section 206 of
the Energy Reorganization Act 46 and was designed
to provide some direct control over vendors andother nonlicensees. It requires maintenance ofrecords and reports of "defects" in fabrication, in-

Responsibilities of the Utility

The licensing and regulatory process describedabove represents the NRC's attempt to discharge
its responsibilities regarding the construction andoperation of a nuclear power facility. The licensing
and regulatory process places the burden on theapplicant to demonstrate that the plant can be
designed, constructed and operated with "reasonable assurance" that it will not endanger public5Even though the ultimate responsibility for theutility's Quality Assurance Program rests with theutility itself, its implementation may be delegated toothers, including architectural-engineering or construction firms, so long as the program's results arereported to an appropriate level of utility management. 47 Appendix B to 10 C.F.R. Part 50 specifies
that design, material purchased and special types ofactivities (such as welding) be subject to inspection
and testing, and any deficiencies thus discovered
must be reported to the NRC.

stallation, or construction of a nuclear facility and its
component parts.
The major review of vendor responsibility comesthrough the Quality Assurance Program. As discussed previously, the licensing process requires
each applicant to establish a Quality Assurance
Program, which must include the vendor's fabrication and testing process. The licensee is responsible for establishing a program that will ensure thatthe vendor will deliver a reactor system meeting
NRC standards. Further, IE's Region IV officedirectly inspects each vendor's facilities to ensure it
has a quality control program sufficient to meet NRC
standards and Part 21 requirements.
Although nothing other than the quality assurance
analysis and 10 C.F.R. Part 21 appears legally tobind the vendor into a relationship with either the
licensee or the NRC, vendors traditionally haveplayed an active role in the nuclear design process.
If there are unresolved safety issues in a design,vendors may undertake the necessary research andmake the results available to licensees, who mustthen convince the NRC of the system's safety. Obviously, this is to the vendor's economic advantage,
because no future orders would be received for any
design that could not pass NRC review.
Once an operating license has been granted for a
vendor's design, the vendor's relationship with theli censee does not end. Through a system of contracts and arrangements, the vendor may continue
to provide information and technical support on its
units; and, as the Three Mile Island accident demonstrated, the vendor sometimes becomes actively involved in analyzing the plant's design, either for retrofitting or during an accident. Thus, vendors havesome continuing obligations to the utilities that purchase their design; to the NRC which must deal withthe design's generic problems; and to the public ingeneral.
The relationship of architect-engineers and construction firms is quite similar to the reactor systemvendors, although the former are perhaps less often
i nvolved in the ongoing problems of nuclear facilities. Like the vendor, the architect-engineering firm
and the construction firm are indirectly regulated
through the NRC's Quality Assurance Program and10 C.F.R. Part 21. Record-keeping and reporting requirements for defects are imposed on thearchitect-engineer and construction contractor byPart 21 as well. Additionally, NRC regulations provide standards and specifications that certain com41
The architectponents of the plant must meet .
engineer must select critical equipment, such as
pumps, reactor vessels, and piping, which conformto these codes and to the General Design Criteria.

NRC Coordination with Responsibilities of Other
Federal Agencies

Although the NRC has primary responsibility inmatters of radiological health and safety, many other
Federal agencies have some responsibility for theconstruction and operation of nuclear powerplants.
These agencies generally deal with matters understatutory authority other than the Atomic Energy
Act. Where there are conflicts or overlapping
responsibilities, memoranda of understanding havebeen entered into to resolve these differences. 48
Although there is some public confusion, theNuclear Regulatory Commission is not part of the
Department of Energy (DOE). Since the separationof the Atomic Energy Commission into the NRC andthe Energy Research and Development Administration (ERDA) in 1974 effected by the Energy Reorganization Act of 1974, P.L. 93-438, 88 Stat. 1233,
42 U.S.C. 5801 et seq., the NRC has been an
i ndependent regulatory agency. ERDA became partof the DOE in 1977, Department of Energy Organization Act, P.L. 95-91, 91 Stat. 565, 42 U.S.C. 7101
et seq., and that department assumed the operationof the national laboratories which had developed
and tested nuclear capabilities under both the AEC
and ERDA. DOE, therefore, has inherited a great
deal of expertise in nuclear matters and, in times of
emergency, assists the NRC in monitoring radiation,
maintaining communication and other technical support activities.
The Environmental Protection Agency has theauthority to evaluate the environmental impact ofthermal water pollution of a nuclear plant, and the
EPA must issue a New Point Discharge Elimination
System Permit before any discharge is permitted.
The EPA also is responsible for setting national emission standards for radiation releases into the atmosphere, and it advises the President of the UnitedStates on matters related to radiation and the environment and has certain other responsibilities re49
The Nalated to emergency response planning.
tional Environmental Policy Act requires the NRC to6

evaluate the impact of thermal pollution in deciding
whether to issue a construction permit, and theCommission and the EPA work together in evaluati ng the impact of water pollution from a plant.
NRC also coordinates with the Departments ofI nterior, Agriculture and Commerce, and the Army
Corps of Engineers, each of which may have certain
concerns that may be implicated in plant siting
determinations. Similarly, the Food and Drug
Administration's Bureau of Radiological Health issues guidelines regarding the safe use and disposalof radioactive products, and other FDA Bureaus
have responsibilities that may overlap with the
NRC's in certain cases. The Occupational Safety
and Health Administration of the Department of Labor has
responsibilities for the safety of the work
50
place, and the Commission and the Department ofTransportation and the U.S. Postal Service share
responsibilities related to the transportation of radioactive materials.

By 1977 there were 70 such planning elements
necessary before a plan would meet minimum NRC
standards. Six States submitted successful plans in
1978. At the end of 1979, there
were a total of 14
53
such successful State plans.
In addition to emergency response planning, the
NRC maintains close contacts with State agencies
ors areas of potentially conflicting authority. For example, the NRC has published a guide to energy facility siting to assist the States and has entered into
agreements with several States on environmental
matters. Although not relevant to nuclear plants,
States may be given responsibilities over small
amounts of special nuclear materials by becomingan Agreement State with the NRC. Under this arrangement, NRC transfers its authority over byproduct material to the State in certain areas.
b. The NRC Assessment of the Basis for
Reactor Safety

NRC Coordination with Responsibilities of State andLocal Agencies

Although individual Commissioners and seniorCommission staff members have testified regarding
the basis for the Commission's assessment of reacfor safety, 54 the NRC as a collegial body has neveri ssued a statement on this subject. Press andCongressional interest in the NRC's policy statement of January 18, 1979 on the Reactor Safety
Study 55 apparently resulted in an attempt by theCommissioners to agree on such a statement.ss
That attempt was not completely successful, however, and Chairman Hendrie testified individually as"the Chairman of the NRC" before a House Subcommittee on February 26, 1979 57 rather than as
official spokesman for the entire NRC. Nevertheless, this prepared testimony is relevant to the inquiry. First, it is the most comprehensive statementon the subject by a member of the NRC andpresumably represents the Commission's best effort, as of the date of the testimony, to reach collegial agreement on the subject. Moreover, because
this testimony was given only a relatively short time
before the March 28, 1979 incident at TM1-2, it isfair to conclude that it represented at least the
Chairman's understanding of how the NRC
assesses reactor safety.
The prepared testimony and the Chairman s oral
testimony are printed in their entirety in the recordof the Congressional hearing.ss Portions of his
prepared testimony are as follows:

The Federal Government (through the NRC) has
the principal responsibility for matters of radiologicalhealth and safety associated with a nuclear powerplant. 51 I n all other areas affecting nuclear plant
construction and operation, States have the authority to regulate, although their authority is sometimes
coextensive with Federal authority. Thus, except as
noted, the full range of what is legally known as"police powers" may be exercised by the host Stateof a nuclear powerplant. These include fire and poli ce protection, zoning controls and environmentalli mitations unrelated to radiation safety, and taxing
powers.
Among these police powers is the emergency
response responsibility of a State for its citizens in
the event of an accident at a nuclear plant. The
NRC has the lead role among Federal agencies indeveloping plans for radiological emergencies.
( Others involved include EPA, DOE, DOT, HHS,
FEMA, and HUD.) In this capacity, the NRC ischarged with reviewing and concurring in State andl ocal radiological emergency plans, and theCommission's analysis of a utility's emergency
response plan submitted with its construction permit
application includes an assessment of the capacityof the State and local agencies to respond.
Numerous guides exist on development of theseemergency plans and the Federal Government hasoffered substantial assistance in training local agencies. 52 NRC guides are updated to include elements which must be considered in a complete plan.

I will turn now to the first topic in your letter announcing these hearings, Mr. Chairman: What isthe basis for the Commission's assessment ofreactor safety? The best answer to that is our re-7

gulatory system, which depends upon having nuclear plants sited, designed, constructed, andoperated on the basis of conservative application ofsound and accepted engineering principles, on requirements for multiple and redundant safety systems, and on a set of regulatory requirements thatare updated to reflect operating experience. The
designers, builders, and operators of these plants
are required to have quality assurance programsand their work is subjected to a continuing licensing
and inspection process by the NRC. The results of
the licensing and inspection process are, in turn,subject to independent review by the Advisory
Committee on Reactor Safeguards and often to examination of public hearings.

Basis of Safety

The underpinning for our safety assurances is ourlicensing process. It provides for the issuance ofconstruction and operating licenses only after
multi-level review that includes public participationand input at its key stages. The licenses issued inaccordance with this process specify the framework and necessary details of actions thatdesigners, builders and operators of nuclear power
plants must follow in order to provide assurance
that there will be no undue risk to the public healthand safety. Compliance with the license conditions
i s enforced by NRC inspectors during plant construction and operation. This system has beenstrengthened further with the assignment ofresident inspectors at operating reactors, reactors
under construction, and fuel facilities.

We believe this regulatory system has served us
well. It is a rigorous system, and appropriately so
in view of the technology we regulate. It is our job
as regulators to make sure that there is no undue
risk from licensed facilities and, while one mustacknowledge strongly held views to the contrary,over 400 reactor-years of experience to date give
us some reason to believe we are on the righttrack.

Licenses are issued for those nuclear power plants
which, based on careful and independent reviewsby the NRC staff, the Advisory Committee on Reacfor Safeguards, a Licensing Board, and if necesnary, an Appeal Board or the Commission itself, arefound to meet the safety criteria and standards required by our regulations. These safety standards
i nclude requirements for considerable margins
between design and operating conditions and for
redundancy in primary and backup equipment, inorder to compensate for the fact that no body ofknowledge can ever be complete enough to reduce
uncertainties and risks to zero. Thus, although theoperation of nuclear power plants is not risk-free,the safety objective of the NRC, as implemented
through this licensing process, is to require plantbuilders and operators to take all those actions
considered necessary to assure that the risk topublic health and safety is, and continues to be acceptably small.

I am going to outline the essential elements of theregulatory system which gives us our assurance ofreactor safety and I will be emphasizing the strong
points of that system. In doing so, I do not want toleave the impression that everything is just fine andthat there are no problem areas. Like most humani nstitutions, our regulatory system is an evolving
one and it is certainly not perfect. As you know,
there are a number of safety issues, some of which
we touched on at your hearing last Thursday, thatare in various stages of resolution and that may require changes in plant design. Steam generator
tube integrity in pressurizer water reactors, hydraulic phenomena in the containments of boilingwater reactors, stress-assisted corrosion in reactor
primary coolant system piping, environmental qualification of safety-related electrical equipmentthese are some of the safety issues listed in the report to Congress on such matters. We believe wehave sufficient understanding of these issues andhave taken appropriate steps in the short term toprovide adequate protection of the public safety,
but full resolution of them is still to come.

One of the primary tools in achieving this safety
objective is that use of the defense-in-depth concept for protecting public health and safety. In its
more general application, this concept calls for thei ncorporation of three levels of safety in nuclear
plants.
The first level requires that measures be taken to
design, build and operate a nuclear power plant so
it will, with a high degree of assurance, operate
without failures that could lead to accidents. The
plant is designed to conservative standards so that
it will be safe in all phases of operation and have asubstantial tolerance for errors, off-normal operation and component malfunction.

In other areas, we are examining many of our regulations with a view to improving and upgradingthem. Part 100, our siting regulation, is an example.
Like our regulations, our licensing, inspection, andsafety research programs could be improved. So
could the quality assurance programs of our applicants and licensees, which occasionally are founddeficient in one aspect or another; and our processof reviewing and inspecting industry quality assurance programs for compliance with our regulatons could be improved. However, I think all these
programs are on balance, very good and, judged
against past efforts by society to control new technologies, are outstanding. But again, they are not
perfect; they can and should be improved; and weare working to do just that.

Despite the care that is taken in design, construction and operation to avoid equipment failures
or operating errors that could lead to safety problems, some failures or error must be expected tooccur during the service life of a nuclear power
plant. The second level of safety requires the provision of measures to cope with them. Protection
for the reactor operating staff and the public is provided by protection devices and systems designed
so that expected occurrences and off-normal con8

ditions will be detected and either arrested or
accommodated safely. The requirements for these
protection systems are based on consideration of aspectrum of events that could lead to off-normal
operations which the plant design must accommodate. In addition, testing programs are required toverify that the protection systems will function as
designed.

hearings conducted by the Commission's Atomic
Safety and Licensing Boards. The reviews aredesigned to assure the proper and conservative
application of the Commission's regulations whichi mplement the defense-in-depth concept. The purpose, scope, and effect of these reviews in minimi zing public risk can best be shown by relating themto the siting, design, construction, and operation
phases of nuclear power plants.

The third level of safety supplements the first two
by requiring design features and equipment to protect the public, even in the event of the occurrenceof very unlikely accidents. The additional safetymargins provided by these features are assessedprimarily by eva!uating the response of the plant toa number of assumed accidents, involving in most
instances the assumption of an independent failureof an element of the protective system simultaneously with the occurrence of the accident they areintended to control. From analyses of these postulated accidents, a number of sequences called"design basis accidents" are selected as a basis forthe design of the additional plant features andequipment that are provided to further protect publi c health and safety. One of the third-level requirements for all nuclear plants is the emergency corecooling systems that are designed to cool the corei n the event of a major instantaneous rupture of thenormal plant cooling systems.

SitingApplication of the defense-in-depth concept also
resulted in the provision of mutiple physical barriers
between the radioactivity contained in the reactor
fuel and the environment outside the plant. The fueli s contained in a sealed metal cladding; the clad fueli s contained in a heavy steel primary coolant system; and the primary coolant system is enclosed ina sealable containment building. The defense-indepth concept is also applied widely in the design
and review of many of the individual systems of theplant, leading to requirements for redundant and independent subsystems and backup systems.
These requirements are embodied in NRC regulations, standards and regulatory guides that are
based on sound engineering practices establishedover the past twenty years, and that undergo continued review and improvement as operating experience accrues. Our comprehensive research
program provides the technical bases for the confirmation of NRC's safety decisions and for neededi mprovements.

The principal NRC requirements for the siting of nuclear power plants are found in our regulations in 10
CFR Part 100 and its Appendix A, Geologic and Seismic Siting Criteria for Nuclear Power Plants. The
siting reviews carried out by the staff in implementi ng this regulation, play an important role in assuri ng that the likelihood of severe reactor accidents
due to siting considerations is very low. For exampie, the requirements of this regulation, supportedby the independent evaluations of seismic and geol ogic conditions at and near a reactor site by the
NRC staff and its consultants, provide the basis forestablishing the seismic design parameters for aplant. The seismic design parameters are required
to be conservative enough so that the likelihood ofan earthquake more severe than the design basis
earthquake is very low, and the possibility of asevere accident resulting from such an earthquake
is even lower. Similarly, NRC regulations requirethat other environmental considerations that havethe potential to cause a severe reactor accident,such as flooding, tornadoes, industrial accidents at
nearby facilities, and overflying aircraft, be evaluated and designed against.

DesignThere are many NRC regulations that require thei mplementation of the defense-in-depth concept in
the design of nuclear power plants. These include
the majority of the present 64 General Design Criteria, other Appendices of 10 CFR 50, and Section
50.55a, Codes and Standards for Nuclear Power
Plants. A large amount of the effort involved in
NRC design reviews is for the purpose of determini ng whether these requirements are being properly
and conservatively implemented, and we rely heavily on these detailed design reviews for our assurance that we are achieving our safety objective.

The NRC Standard Review Plan, first published in1975 after years of development, provides documented guidance for the staff and applicants as tocurrent staff positions on acceptable ways to implement the regulations. It consists of over 1400
pages of detailed criteria and methods used forsafety reviews and evaluations.

I n addition to the design reviews performed by the
NRC staff, our regulations require license applicants
to perform analyses of various postulated equipment, system, and personnel failures. Independent
evaluations of these events on a selective basis arethen performed by the NRC to assure that equipment and personnel performance under the assumed conditions are properly described and theaccident consequences conservatively calculated.
These independent accident analyses provide
further assurances of the design adequacy oflicensed nuclear power plants.

These comprehensive safety reviews are performed by the NRC staff during plant design, construction, and operations. Independent safety reviews are also conducted by the Commission's Advisory Committee on Reactor Safeguards, and theresults of these reviews are discussed in the public
9fire protection inspections. In response, licensees
instituted a number of immediate improvements infire protection at their plants. A generic task activity was initiated by the staff to develop upgradedguidelines for fire protection in nuclear power
plants. The generic task culminated in mid-1976
with the issuance of a revised Standard Review
Plan section on fire protection. At that time westarted a reevaluation of each operating reactor
against the new guidelines and we are requiring appropriate plant modifications to upgrade fire protection. The new guidelines have been used as abasis for fire protection review for all operating
license and construction permit applications underreview since mid-1976.

Construction and Operation

Appendix B to 10 CFR Part 50 of the NRC regulations establishes mandatory quality assurance criteria for all phases of nuclear power plant design,
construction, and operation. These criteria are implemented by field reviews

Each license for operation of a nuclear reactor contains Technical Specifications, which set forth theparticular safety and environmental protection
measures to be imposed upon the plant, and theoperating conditions that are to be met in order toassure protection of the health and safety of the
public and of the surrounding environment.

The NRC's Office of Inspection and Enforcement
continues its inspections during the operating life of
the plant to ensure that the requirements of NRC's
licenses are enforced, that problems arising inoperation are well handled, and that valuable feedback from operating experience is made available
to other licensees and incorporated into the safety
reviews of other plants. Furthermore, NRC licenses
require utilities to test important safety systems
periodically and to report failures of all safetyrelated equipment to the NRC. I should note that
we have some steps underway to improve this process of getting operating experience and testing information out to other licensees. The results of
NRC inspections and reports of equipment failures
are routinely made public.

I n summary, the NRC recognizes that the operationof nuclear power plants presents some element of
risk. But we believe that our process, which involves a well-developed safety approach, thespecification of safety design requirements to implement that approach, and an extensive safety review, licensing and inspection process, gives reasonable assurance that risk is comparatively verysmall.

The safety record so far achieved in the operationof nuclear power plants gives support to the validityof the NRC approach. We have had, at this point,
approximately 440 reactor-years of operation ofli censed commercial nuclear plants in the UnitedStates without an accident having significant effecton the health and safety of the public. While thisexperience is, of course, much less than that needed to prove our belief that large reactor accidents
have a low probability of occurrence, it is an encouraging record and an outstanding one for a maj or industrial activity.

The continuing review of operating experience bylicensees and by the NRC staff provides anotheri mportant contribution to the assurance of nuclear
power plant safety. Design improvements, basedon this experience, can be incorporated into newplants, and any mistakes in design and constructionof operating plants can be corrected.

NRC's regulatory process has relied and will continue to rely on the judgment of highly skilled engineers and scientists as the source for its safety
decisions. Based on the aforementioned considerations, and without prejudice to any conclusion
we might reach in any individual licensing proceedi ng, we believe that nuclear power plants designed,
constructed, licensed to operate, and operated inaccordance with our regulations and requirements
present no undue risk to the public.

Even after nuclear plants begin commercial operation, they are not insulated from safety improvements. There has been a continuing NRC programof improvements in existing nuclear power plants,
based on operating experience, new criteria, andbetter understanding of safety issues throughresearch, testing and analysis. As the number ofoperating nuclear power plants has increased over
the years, there has been a corresponding increasei n the allocation of NRC staff resources to the inspection program and to the technical safety
evaluation efforts necessary to provide continued
assurance of safe operation of licensed reactors.

It would be nice to be able to say that there are absolutely no problems with respect to the safety of
nuclear power plants, that perfection has beenachieved, and that all risks have been eliminated.
This is not the case. While we believe that nuclear
power plants are adequately safe, in the ordinary
sense of the word, and that the risk to the publichealth and safety from their operation is very small,the Commission's intention is to assure that thisrisk remains very small so that nuclear power cancontinue to represent a suitable and safe alternative
for satisfying a portion of the nation's electrical energy needs.

One of the many examples of the feedback ofoperating experience to upgrading of safety requirements involves fire protection. After the
Browns Ferry fire in March 1975, an NRC Special
Review Group was established to identify the lessons learned from this event and to make recommendations for the future. As a result, theCommission's Office of Inspection and Enforcementi ssued bulletins to licensees and initiated special

10

c. The Licensing and Regulatory System for
Nuclear Power Reactors: An Overview of Its
Major Deficiencies in Assessing Reactor
Safetyi ndependent bodies who largely depend on the NRC
staff for the information they need to appraise thatvery staff's judgments. Ultimately, the present review structure makes the staff's position even morei mpenetrable to independent review.
The present regulatory system is also characteri zed by substantial diffusion of responsibility and accountability. The present organization is fragmented, and little NRC attention has been given to therelationships of the various staff offices. Effective
overall management controls are nonexistent, andthe NRC's failure to provide general policy guidance
fosters a system affording considerable amounts ofunbounded, and effectively unreviewed, discretion to
the staff members who make the technical engineering judgments that ultimately determine thedegree of safety to be required in a nuclear plant.
The present system for licensing and regulating
nuclear power reactors has consistently promised
substantially more than it has delivered. This section provides a general overview of its more important deficiencies in this regard.

I ntroduction

Although the system for licensing and regulating
nuclear powerplants has been heralded as one
safeguarded by separate reviews by independentbodies during the various phases of the licensing
process, this is a false assurance. In fact, the
NRC's staff, whose resources for technical review
substantially exceed those of the other reviewing
bodies, decides virtually all of the safety issues thatare resolved in the licensing process, and likewisedetermines which safety issues need not be
resolved in that process. By the time the other independent bodies become involved most of thosedeterminations have been made. Thus, as a practical matter, the review of the NRC staff's safety
determinations by the Advisory Committee on Reactor Safeguards (ACRS) and the Atomic Safety andLicensing Board (ASLB) is a ritualistic process, theresult of which is effectively predetermined.
The ACRS is the one body offering the potential
for an independent technical review of staff safety
determinations. The advisory committee's actual
contribution has been disappointing, however. The
end result of the ACRS' review typically is a cryptic
advisory letter concluding that the plant can be constructed and operated safely if some concerns are
addressed, to some degree, by some entity in the
future.
The review of the ASLB also contributes little to
the regulatory process. Regrettably, hearings before the board are more a legal and procedural tour
de force than a forum for open and candid discussion. No one, not even the members of theseboards, seriously contends that they contribute substantially to the quality of the technical review.
Finally, the NRC's Commissioners, who justify
their isolation from the staff determinations in individual licensing cases on the ground that they may becalled upon to review the ASLB's decision in theformal review process, usually decide not to grant
review of plant-specific technical issues.
Thus, the existing review structure provides legal,
procedural, and institutional shields to the regulatory
staff, generally assuring that its actions and inactions will ultimately prevail without substantial modification or correction. The staff's determination of
the acceptable level of safety typically prevails
without any penetrating review and is approved byPractically All Safety Issues Are Resolved by theStaff

One who is neither an experienced observer nor
a participant in the licensing process for nuclear
power reactors might assume that the staff's resolution of most, if not all, of the important safety issues is effectively reviewed or monitored by othercomponents of the regulatory system. This is not
how the system operates in practice, however. In
fact, the substance of the NRC's licensing and regulatory functions are carried out almost exclusively
by a technical staff trained in various engineeringand scientific disciplines relevant to nuclear powerreactors. These persons review the license applications, establish the safety requirements, develop
standards and recommendations, conduct inspections, take enforcement actions, and administer
research programs. These persons realisticallycontrol most licensing and regulatory actions. Even
where hearings must be held regarding permit orli cense authorizations, practically all safety decisions are made outside the formal hearing processby the regulatory staff during its lengthy application
review. For all practical purposes, these decisions
are routinely made by the staff without substantial
oversight by anyone.
Even though an organizational analysis of theli censing function may suggest that staff safety
determinations may be reviewed at various points in11the regulatory process, in fact, the effectiveness ofthese reviews is minimal. Each of the bodies thatappear to be in a position to exercise effective oversight of staff safety judgments in the licensing
process-the ASLB, the ACRS, and the NRC
itself-has certain limitations that have impaired its
contribution to the process.

before the "trial" before a licensing board whosefavorable decision is a necessity for the license to
be issued. Unfortunately, the advisory committee's
potential has not been realized.
Like the licensing and appeal boards, the advisory committee depends primarily on information furnished in the staff's Safety Evaluation Report. The
product of the advisory committee's review is typically a cryptic advisory letter, generally concludingthat the plant can be constructed or operated safely
provided that some of the committee's concerns are
addressed by someone at some undefined date.
With this, the committee's involvement in the review
process ends. As of March 28,1979, it is fair to saythat the advisory committee, as a collegial body, had
not recently criticized the quality of the technical review process, and did not aggressively assure that
the NRC staff responded to its concerns. The committee seemed to share the views of the staff, andpresumably the NRC, that individual licenses could
be issued with a substantial number of generic issues to be decided at some future time.
Substantial dissatisfaction exists regarding therole of the ACRS and the manner in which it performs its function. In view of its limited resources,
the advisory committee depends heavily on the NRC
staff for information. The committee is not satisfied
with the quality of the staff reports submitted to it,or the presentations of those who appear before it.
The staff's performance before the committee has
been unenthusiastic, if not constrained-in part because of the staff's low regard for the committee's
contributions and in part because many of thesesame staff members recognize that they may becalled to testify before the licensing board. Similarly, the ACRS is not satisfied with its relationship with
the Commissioners or with the leadership exhibitedby the regulatory staff. On the other hand, those
who appear before the ACRS regard many of its
discussions as vague and unfocused, and many of
the comments offered by the committee in particularcases as largely consisting of vague generalities
that contribute relatively little to the licensing process.

Advisory Committee on Reactor Safety

The Advisory Committee on Reactor Safety, or
ACRS, is an independent, part-time, and advisory
statutory committee, whose basic charter is to "review safety studies and facility license applications
referred to it and ... make reports thereon, ... advise the Commission with regard to the hazards ofproposed or existing reactor facilities and the adequacy of proposed reactor safety standards, and ...
perform such other duties as the Commission may
request." 59 I n addition, beginning in 1977, the ACRS
has been required to "undertake a study of reactor
safety research and prepare and submit annually to
the Congress a report containing the results of suchstudy."soThe advisory committee exercises an independent review over staff licensing actions and generall y reviews proposed changes in regulations and regulatory guides that are of safety significance. As
part-time advisors its members cannot, and do not
attempt to, duplicate in detail the staff's review in individual licensing cases. Moreover, staff regulatory
actions taken outside the formal licensing process
are not routinely reviewed by the ACRS.
As its title indicates, the function of the ACRS isadvisory only. Thus, ACRS safety determinations or
recommendations in individual licensing reviews are
not regarded as substantive evidence of those particular issues or concerns in hearings before the
ASLB. The ACRS determinations are entered in the
hearing record simply to demonstrate the NRC's
compliance with the statutory requirement of consultation with the ACRS, not for the substance ofthe concerns that the advisory committee may haveraised. If particular issues raised by the advisorycommittee are not independently sponsored by oneof the parties to the hearing, they are not regarded
as having been put in issue, and they need not be
considered by the licensing board.
The ACRS is one component in the review process that offers the potential for effective, independent technical scrutiny of the staff's positions on
safety issues. The committee's review of an application and the staff's position on that application
comes near the end of the staff's review of the application, after the staff has reached its position, but

Atomic Safety and Licensing Boards

The Atomic Energy Act requires a public hearing
before an Atomic Safety Licensing Board prior to
the grant of a construction permit. 61,62
Beyond their general responsibility to preside at
public hearings on the licensing of nuclear powerplants, the ASLB's role with respect to nuclear
reactor safety matters is unclear. These boards
must decide the issues raised before them, but
12for years pointed out that many of the regulations
are ineptly drafted-some to the point of being virtually incomprehensible-and that others have quite
obvious gaps in them. None of these findings haveresulted in any substantial overall corrective action
from the NRC, however.

beyond this mandate, the NRC has not given the
ASLB positive, unambiguous, and realistic policy
directives. The NRC's emphasis instead has beenon encouraging expedition and, concomitantly, on
describing what the boards are not expected to do.
Consequently, the boards do not, and should not be
expected to, conduct an extensive review or auditof the quality of the NRC staff's safety review.
Almost without exception, the issues before aboard are raised by interested members of the public who have intervened as parties in the proceedi ng. Boards are called upon to decide on the basisof a record made principally by the applicant, who istypically supported by the NRC staff, and by an opposing intervenor. The board itself has no responsibility to produce a record, however, and its decisional work must be based on the record producedby parties who usually are grossly mismatched inavailable resources, and who advocate widely divergent positions. The outcome is virtually predictable;
almost without exception, the position advocated by
the applicant and NRC staff ultimately prevails.
Practically all experienced observers-including
most of the ASLB members who responded to aSpecial Inquiry Group questionnaire-believe thatthe formal hearings do little to enhance the quality ofsafety assurance for a specific nuclear powerplant.
I ndeed, some believe that the formal proceedings
discourage applicants and the staff from dealing
with all sides of controversial safety issues in theirsafety analyses and evaluations.

The Role of the Commissioners in Individual License
Determinations

Although one might expect the NRC as a collegial
body to play a substantial role in significant licensing
determinations regarding individual plants, that is not
the case. As previously indicated, NRC review of
appeal board determinations in individual proceedings is not common. Ironically, however, the NRC's
ex parte rule, designed to preserve the Commissioners' impartiality so that they can perform thisappellate function, isolates the Commissioners frommeaningful contact with the regulatory staff.
The Commission's ex parte rule effectively provides that after a matter has been noticed for ahearing, no Commissioner or member of his or her
staff who advises in these appellate functions may
consult the technical staff with respect to mattersthat may become relevant to the particular facility. 67
The ex parte rule thus erects a barrier between theCommissioners and their best source of information
on licensing-the staffs of the Office of Nuclear
Reactor Regulation (NRR) and the Office of Inspection and Enforcement (IE). This further isolates theCommissioners from the licensing process, and fromthe myriad safety determinations that are resolved
at that level but do not rise to the Commission's
consideration in the formal appeal process.

The Atomic Safety and Licensing Appeal Board

Although the NRC itself, under the law, is the final
administrative decisionmaker in the licensing and regulatory process, it has delegated substantially all ofthat authority to the Atomic Safety and Licensing
Appeal Board (ASLAB). 63 A party may seek NRC
review of an appeal board decision on the groundthat the decision "is erroneous with respect to an
i mportant question of fact, law, or policy," 64 and the
NRC may, "in cases of exceptional legal or policy
i mportance, review the decision or action on its own
motion." In practice, however, NRC consideration of
appeals from the appeal board is rare; the appeal
board generally has the final word on issues raised
before it.65
The NRC's failure to meet its responsibility toprovide a complete and unambiguous set of regulations has exacerbated the appeal board's difficult
tasks. The appeal board for years has devoted agood deal of its time and effort to interpreting the
NRC's substantive regulations and their application
66
The board and others haveto the facts of record.

A Substantial Number of Licensing and Regulatory
Actions Are Taken Outside the Formal License
Authorization Process

The bulk of the NRC's technical resources onreactor safety issues is in its regulatory staff. The
majority of safety issues are reviewed, evaluated,and have safety judgments rendered at the staff
level. For cases that must go to hearing, thisevaluation and judgment is reflected in the staff's
Safety Evaluation Report in which the underlying
reasoning and evaluations may be either sparse oromitted. Typically, that staff judgment prevails.
A substantial array of other licensing actions taken by the staff typically neither go to hearing nor receive review by anyone outside the NRR. These include:. Granting or denying amendments to a construction permit or to an operating license;13• Determinations that proposed changes in facility
design or procedures do not involve an unreviewed safety question and therefore do not require any license amendment;• Determinations to increase or to decrease safety
requirements at a particular plant;• Determinations to apply new regulatory requirements on a plant-specific basis;• Determinations that a safety issue is generic andtherefore need not be resolved on a plantspecific basis;• Determinations of whether a staff technical positon should be maintained if an applicant licensee
seeks internal review of that position;• Determinations that a component, system, or
equipment is safety grade or non-safety grade.

guidance on what level of risk Congress considers
acceptable. Instead, present law charges the NRC
with the responsibility to determine that its licensing
and regulatory requirements "will provide adequate
28
protection to the health and safety of the public"
and to "prescribe such regulations or orders as it
may deem necessary" to govern any activity authorized by a license "in order to protect
health and to69
minimize danger to life or property."
However, there has been no national policy to
study and compare societal risks from presently accepted means of generating electricity and no clear
identification of priorities exist among the choicesthat can be made. Certainly this is a fundamental
defect, and these basic judgments should not be left
to an independent regulatory agency in the licensingof individual nuclear powerplants.
The NRC is given almost unlimited discretion toact in the licensing and regulation of nuclear powerplants within a statutory authority bounded only by
thebroadest of standards.
This statutory
approach-like the Commission's licensing and regulatory system itself-was developed during theevolutionary phase of nuclear powerplants, and has
not been changed to recognize new policy issues
relating to the commercial use of nuclear powerplants.
Other than repeating the regulatory truisms that"public safety is the first, last, and a permanent consideration in any decision on the issuance of a construction permit or a license to operate a nuclear facility," and that the NRC must have "reasonable assurance" that public health and safety are not endangered by its licensing actions, the Commission,
as a collegial body, has given the staff essentially no
substantial policy direction and guidance. 70 Thus,
as of March 1979, the licensing and regulatory system operated under essentially the same general regulations, guides, and practices as it did on January
19, 1975 when the NRC came into existence. Other
than structural changes in the organization as required by the Energy Reorganization Act of 1974,
the existing system continued without policy directives and guidance. 71
As a collegial body, the NRC has given the staff
little guidance on what it deems to be acceptablelevels of risk in nuclear reactor safety. Although
millions of dollars were spent and a massive effort
undertaken by the government in the Reactor Safety Study,72 the NRC did not direct the staff to use
the methods and techniques of that study toenhance reactor safety. The licensing and regulatory staff did not use these techniques to any appreciable extent prior to March 1979. 73 Similarly, after
the issuance of the Lewis Report in September

In addition to these judgments related to a particular licensing process, the regulatory staff is also
responsible for making safety judgments in moregeneral areas of policy and planning. Obviously,
these determinations have a pronounced impact on
the safety of particular plants. These more generalareas include:• The nature and focus of the inspection and enforcement process;• The evaluation of operational information;• I nterpretation of regulations and regulatory
guides;• The need for and allocation of resources;• The priority for additions to, or changes in the regulations and guides.
The System Is Not Bounded by Definitive StatutoryStandards or Regulatory Objectives
Two fundamental questions, which go to theheart of the NRC's regulatory responsibilities, are involved in making safety evaluations and decisions
for nuclear powerplants. How much safety is needed and how much is provided? The answer to thefirst question-identifying the acceptable degree ofrisk-inescapably should be a policy decision madeby the people through their elected representatives.
The answer to the second entails an evaluation of
the risk being taken measured against the benchmark of acceptable risk. This answer should bedetermined in the engineering and scientific arenaby those who are responsible for making the safety
evaluations.ss However, no helpful guidance has
been given to staff reviewers in quantifying the levelof acceptable risk by either the Congress or the
NRC. The NRC's statutory mandate provides it no14

i s largely left to the directors of the NRC's five program offices (see Appendix 1.1). Responsibilities are
fragmented within those offices, and the absence ofeffective checks and balances within the system orany effective oversight from the outside has createdand perpetuated a system in which each office attempts to look after its own interests as best it can.
The Office of Nuclear Reactor Regulation (NRR)
plays the predominant, and for all practical purposes, the exclusive role in the majority of nuclear
reactor safety decisions that arise during the application review and after the license is issued. However, even at the office level, it is not clear who is
responsible for being office spokesman. NRR appears to speak with many voices and at many different levels on reactor safety issues. This gives
outsiders the impression that confusion and uncertainty exist within the Commission on technicalmatters, and that the Commission overreacts insome instances but does not act as a regulator inothers.
Apparently this problem is largely a reflection of
the substantial fragmentation existing within the
NRR. The most notable examples of this fragmencation include the following:

1978, which assessed the achievements and limitations of WASH-1400, the NRC, after extensive debate to reach an acceptable collegial position, issued a policy statement that was essentially negative in tone and created a misleading picture of the
Lewis Report's findings and recommendations on
Summary. 55
WASH-1400
and its Executive
Although the Lewis Report found the Executive
Summary to WASH-1400 and the Study's absolutenumerical assessment of risk deficient in importantdetails, it unequivocally endorsed WASH-1400 techniques as an aid in technical decisionmaking.
Fault-free/event-free analyses should be among
the principal means used to deal with generic safety issues, to formulate new regulatory requirements, to assess and revalidate existing regulatory
requirements, and to evaluate new designs.

The overall negative tone of the NRC's statement,
and its obfuscation of what the Lewis Report criticized and what it endorsed, resulted in policy direction and guidance that seems to have had a negative impact on the quality of the licensing and regulatory system for nuclear power reactors.
As a result of the silence of Congress and the
NRC, the determination of what constitutes "adequate protection to the health and safety of the public," 28 i s largely left to the individual or composite
judgment of members of the staff who conduct
licensing reviews; make recommendations in regulatory documents such as the staff's Safety Evaluation Reports; inspect, enforce, and establish requirements; and administer research programs. The
hard truth is that there is usually no rational basis
given as to the level of risk and how there is adequate protection to the public. In the absence of regulatory policies that logically flow from the establi shment of an acceptable level of risk, and the useof techniques to move licensing and regulation in the
direction of relative risk assessments, the staff is invariably left to apply a series of generalized "rules of
thumb" that appear to be based largely on subjective evaluations, which may be neither neutral nor
objective. Without this risk basis, it is difficult toconstruct a rational regulatory policy or to measure
the effectiveness of the licensing and regulatory
system.75, Approximately 24 technical review branches
scattered among the four divisions that comprise
NRR, review various pieces of an application
under varying review approaches that have gradually evolved over almost a decade;, Technical branches in the Division of Operating
Reactors (DOR), in which technical disciplines
parallel those of other branches, primarily theDivisions of Systems Safety, and Site Safety andEnvironmental Analysis;, A separate Division of Project Management( DPM) that is dependent on the technicalresources in other divisions, thus introducing additional management challenges;, Isolation of the quality assurance, technical qualifications, and operator licensing functions in the
DPM-a division primarily oriented toward meeti ng targeted licensing review schedules;, The initial placement of the responsibility for an
operating reactor in the DPM, followed by ani nternal negotiation process under which that
responsibility is transferred to the DOR. Thisfragmentation effectively removes the DOR froma position of responsibility during the importantmonths of initial operation and creates confusion
regarding who has the responsibility for evaluati ng relevant operational information;. The isolation of the Technical Specifications
Branch in the DOR;

The Absence of Unified and Positive Management
Fosters Fragmentation of Responsibility andI neffective Coordination within the Commission andthe Industry

The NRC is remote from the day-to-day operation of the licensing and regulatory system at thestaff level. As a result, management of the system15• The absence of ultimate responsibility for the review of the nuclear steam supply system in its
entirety by any branch or entity in the technical review area;• The lack of responsibility for the review of theentire plant from the standpoint of systems interactions, which may be of safety significance, inany branch or entity within the NRR. 76

the possible effects of safety changes on a vendor's
contracts with other utilities are realities that cannot
be ignored. (See Section I.E for a detailed discussion in a different, but related, context.). With veryli mited exceptions, however, the NRC has no policy
statement or regulation that addresses this fragmentation of responsibility and its potential consequences.
In addition to these problems of fragmentation of
responsibility within particular offices and within theregulated industry itself, additional problems arise at
the points where various offices and entities within
the NRC interact. The NRC's Office of Inspectorand Auditor's "Independent Review of the Browns
Ferry Fire," states;

Substantial interface problems exist within NRR in
at least two important areas. The first area involves
the transfer of lead responsibility for an operating
nuclear plant from the DPM, which is primarily
responsible for shepherding the application throughthe system, to the DOR, created in 1975 to provide
attention and expertise to operating reactors. Prior
to March of 1979, internal procedure and policy inthis area vested the responsibility for operating
reactors in the DPM for more than a year after
operations began. 77 Consequently, the important
Davis Besse precursor events in 1977 and the entire
operating life of TMI-2 took place when responsibility for these reactors still remained in the DPM.
A second interface problem in NRR relates to theroles of the Divisions of Operating Reactors andSystems Safety. Each of these divisions has techni cal disciplines that for the most part are duplicative.
The respective roles of these divisions, the duplication of technical disciplines in each, and the coordination of their actions on safety issues have been
lingering questions never satisfactorily addressedby NRR management. 78
The NRC has been equally unsuccessful in deali ng with the fragmentation of responsibility within thei ndustry it regulates. A nuclear powerplant is a single unit with a large number of system interactions,some of which are of safety significance. As theapplicant and licensee, the utility is responsible forthe proper construction and the safe operation of
the plant. However, it is obvious that many others
exercise substantial judgment and take significant
actions that may affect the plant's safety. For example, many other entities, such as the equipmentvendors, the architect-engineers, and the construction contractors, are involved in the design, construction, and manufacturing of the thousands ofpieces of equipment and components for the plant.
The only direct regulatory relationship is between
the NRC and the utility. The contractual relationships between the utility and the nuclear steam suppliers, the architect-engineer, the construction contractor, and others are generally entered into prior
to the NRC's review of the license application andmay not always be conducive to sound regulatory
objectives. For example, the issue of who shouldbear the burden of the costs of safety changes andOne area of inquiry during this investigation was thelevel of the relationships between IE, Licensing, andStandards. Certain views were expressed that relations were good and on the other extreme thatthey were lousy. Faced with varying sentiments
such as these, it is perhaps safe to say that the interface could stand improvement. Consideration
should be given to the establishment of a mechanism to improve the existing interface between allelements of the Commission, and we might consider making this problem the subject of a future audit. 79

These words apply with equal force as of March1979.

The Offices of NRR and IE are assigned responsibilities requiring each to deal directly with licensees
on safety, safeguards, and environmental mattersi nvolving the construction and operation of nuclear
powerplants. IE inspects powerplants to determine
compliance with NRC's requirements, applicable regulations, and the commitments NRR extracts inparticular cases. The responsibilities of each office
are discussed in an internal "Agreement on
NRR/I&E Interface and Division of Responsibility"
agreed to by the directors of these two offices (seeAppendix 1.2). The principal responsibilities assigned to NRR are establishment of safety, safeguards, environmental, and antitrust criteria forli cense issuance; evaluation of license and amendment applications; and issuance of licenses andamendments that meet established criteria. NRR
also has responsibility to evaluate the performanceof licensed facilities to establish the adequacy of, orneed for change in NRC requirements. The principal
responsibilities assigned to IE are (1) the inspectionof licensed facilities and activities to ascertain compliance with NRC requirements (2) observation andreporting on the safety of licensed activities (3) investigation of the safety of licensed activities (4) investigation of events reported and allegations received, and (5) effecting enforcement action where16

noncompliance with NRC requirements is identified.
I E also has responsibility for evaluating licensee performance with respect to safety and safeguard
matters, and for providing feedback to NRR.

The effectiveness of these offices' execution of
their shared responsibilities is compromised by defects in the working relationship between the two.
There appears to be neither a fertile feedback of inspection results into licensing and regulatory requirements, nor a general awareness on the part ofi nspectors of special matters that are of safety significance to NRR. If IE becomes involved in initial
evaluations of a licensee event, at some ill-defined
point the "lead responsibility" for the matter istransferred to NRR. Joint NRR/IE teams are notused to observe and evaluate significant operational
events, such as initial systems testing and the ascensions to power tests, and there are no personnel
rotations between NRR and IE.

Even though one of NRR's prime information
sources is the inspector in the field, IE inspectors
have a formidable organizational network tomaneuver before the information reaches the
responsible license reviewer. Division of responsibili ty within IE between its headquarters office andits five regional offices aggravates the problem. IE
inspectors in these regional offices are the sourcesof information for many of the responsibilities of
NRR. The interface line between these inspectors ischanneled through the regional office organizationand through the IE headquarters office, however,there is no direct channel between them and thetechnical reviewers in NRR.
I n addition, the regulatory staff relies on outsidecontractors and consultants, to a substantial extent,
to review sections of applications in the reactor
area. The extent to which the staff is able to or
does manage and evaluate this review work is difficult to assess. It is unclear whether this reliance on
outside consultants reflects NRC constraints, staff
preferences, or other motivations. In any event, thispractice results in further fragmentation of the review.
The relationships among other important components of the regulatory system also require improvement. The communications between the NRC,
NRR, and the ACRS are deficient. The ACRS, which
has technical expertise in nuclear safety matterscapable of supplementing that of NRR and which bystatute has an independent advisory role in thatarea, is not pleased with the staff's lack of response
to some of its recommendations. On the other
hand, the Atomic Safety and Licensing Boards,
which compared to the advisory committee have
limited expertise in the area of nuclear reactor safe-ty, could be overwhelmed by the "Board Notification
Policy," which requires the staff to furnish them witha wide assortment of unevaluated or poorly evaluated information. Thus, the system is apparently
placing primary oversight responsibility on licensing
boards, the entity outside of NRR with little nuclear
reactor safety expertise, and not on the advisorycommittee, the entity established by statute to provide independent and advisory expertise to the NRC
on "the hazards of proposed or existing reactor facilities" and "the adequacy of proposed reactor
safety standards." 59
The precise functions of the Regulatory Requirements Review Committee (RRRC) also merit examination (see Section I.A.3.a). This committee has nocharter from the NRC, is not referred to in NRC regulations, and does not operate under regulatory
criteria that can be applied in practice. The RRRC
i s a staff institution headed and dominated by NRR.
It has no permanent members and no permanent
supporting staff. SO Nevertheless, this committee isthe staff organization that decides whether to impose new regulatory requirements or to relax existi ng ones. Once it makes that decision its task isfinished, and the job of implementing its decisionpasses to others in NRR, who sometimes fail to implement those mandates in a timely manner. 81
The System Does Not Assure That All Important
I ssues Are Identified

The licensing review and the staff's safety
evaluations focus primarily on safety systems
hardware and whether it complies with the designprinciples set forth in the General Design Criteria for
Nuclear Powerplants, 8 or, in rare instances, to more
specific criteria. 82 The licensing review thus largely
consists of an engineering review, designed to compare a particular proposed design system against aseries of established engineering criteria and performance standards. The operational side of nuclear
safety-considerations such as the human element,
the individual machine interface, control roomdesign, qualifications to assume the responsibility
for a nuclear powerplant, operator training, emergency planning, operating procedures, and the systematic evaluations of operational feedback
information-is largely ignored in the licensing andregulation of nuclear power reactors, however. 83
As the experience at TMI-2 illustrates, these considerations can be extremely important to the safe
operation of even properly designed nuclear powerplants. Even if one incorrectly assumed that the engineering review was adequate to perform the task
assigned to it, the failure of the regulatory system to
17The Single Failure Criterion

adequately consider and regulate these operational
factors has now been recognized to be a substantial
shortcoming in the existing regulatory system.

The single failure criterion is a term applied insystems design and analysis to define the required
reliability of the systems needed for safe shutdown
and cooling, and for mitigation of the consequencesof postulated accidents. Simply stated, the single
failure criterion is a requirement that a systemdesigned to carry out a specific safety function must
be capable of carrying out its mission in spite of the
failure of any single component within the system ori n an associated system supporting its operation.
This concept has the direct objective of promoting
reliability through the enforced provision of redundancy in those systems that must perform asafety-related function. Its application involves asystematic search for potential single failure points
and their effects on prescribed missions in order to
identify design weaknesses that could be overcome
by increased redundancy, or use of alternative systems or procedures.
Application of the concept is complicated by theinterrelationships between the various plant systems
i n a nuclear powerplant. Furthermore, there is aneed to define for specific systems the events andassociated assumptions that must be consideredduring application of the single failure criterion.

Principles That Bound the Review

The NRC's design safety review does not requireconsideration of all of the systems and componentsof the nuclear plant, but only of those deemed"safety-related." Moreover, the NRC's licensing review does not encompass a consideration ofdesigns for prevention or mitigation of accidents involving independent failures of more than a single
component or system, such as occurred during theTMI-2 accident. These and other limitations circumscribe the NRC's licensing design safety review.
Design Basis Accidents

The principal tool used by the staff for reactor
safety evaluation is an analysis of a spectrum ofdesign basis accidents. The NRC has postulatednine classes of increasingly severe accidents andoccurrences. The licensing review system is intended to develop reasonable assurances that theplant's proposed design will adequately deal witheight of those categories, assuming that the probability of the most severe accidents is sufficiently remote to exclude that category from review.
The response of the reactor plant to each ofthese postulated events is predicted and the radiological consequences are calculated. The greatestemphasis, both in accident analysis and supporting
research, has always been on assurance of themeans for core cooling under all circumstances,
particularly in the event of a large loss-of-coolantaccident (LOCH). Earlier safety reviews tended toemphasize the concept of a maximum credible accident, and to evaluate the adequacy of the reactorsite and the integrity of its containment in judging
the acceptability of its design and location. As thesize of nuclear reactors increased, the potential for
consequences resulting from the system's inability
to deal with any of the design basis accidents also
i ncreased. However, the regulatory system has
never deviated from the judgment that because theprobability for the occurrence of a highly severe accident is so low, the consideration of these accidents in the regulatory process can be basicallyi gnored. Thus, accidents of increasing consequences beyond design basis accidents, such as
those leading to extensive core damage, or to coremelt, are not dealt with by additional design requirements, despite their potentially awesome consequences.

Safety and Nonsafety Systems

The staff devotes substantial effort in reviewing
safety systems, but pays practically no attention to
those systems deemed nonsafety. This is the practics even for equipment which is in the gray area
between safety-related and nonsafety-related, suchas a power-operated relief valve in the primarycoolant system. 85 There is no clear definition or
guidance to reviewers in determining whether equipment should be deemed to be safety- or
nonsafety-related. 86 The designation of systems as
safety-related or nonsafety-related is done in asomewhat arbitrary and inconsistent manner (seeSection l.A.3.b). Additionally, once a system isdesignated as nonsafety-related, it is difficult tohave the designation changed. This makes it particularly difficult for an IE inspector to effect necessarychanges in systems arbitrarily defined as nonsafety.
I nstead, discussions between the staff and the industry have focused primarily on determining the reli ance that can be placed on nonsafety grade equipment to prevent or mitigate the consequences ofanticipated transients.
Staff Review of the Application

The staff does not conduct an exhaustive reviewof the design of a reactor. It conducts instead an18

audit review of the design as described in the application.
Guidance on procedures for conducting this audit
review are set forth in the Standard Review Plan
( SRP), issued in September 1975. The SRP has
never been followed for the complete review of any
application, however, and it is generally recognizedthat its content is of uneven quality. 87 The plan's
definition and distribution of review responsibilities
are not well established in several review areas, andits discussion of secondary review responsibility
and review interfaces is often inadequate or miss88
ing.
Distinctly different review approaches are foll owed by the staff in some of the different technicalareas. In some areas, a technical review consists
mainly of reviewing an applicant's interpretation ofguides and standards. In others, the staff undertakes an indepth audit of an applicant's design, construction, procedures, and operational practices. Finally, in some other technical areas, the staff's review depends heavily on staff analyses performed
i ndependently of the applicant's analysis. 89
The staff's review of safety systems under the
SRP is done either by organizational units, such as
containment systems, reactor systems and plantsystems; or by technical disciplines, such asmechanical engineering, materials engineering, andstructural engineering. Although systems interactions are considered in the staff's review, no entity
i s assigned that responsibility for the complete
plant. Thus, there is no mechanism for assuring thatthe staff's audit review adequately considers the interaction of various plant systems, particularly withregard to whether actions or consequences in one
system could adversely, affect the redundancy andi ndependence of safety systems.90

technical specifications. These systems are reviewed periodically by an inspector at some level offrequency, by varying methods, and in varying detail.
Some inspection efforts do not have direct association with plant systems, but rather with generalactivities such as training, which is important tosafety. Some of the inspection effort also involves
auditing the plant surveillance program, which has
the objective of assuring the operability of accident
mitigating systems. Finally, the inspection effort
also involves some review of the plant's operatingprocedures. This review does not generally appear
to involve an indepth examination of the adequacyof these procedures, however, or even those whichappear to be important, such as emergency procedures. The review is primarily an accounting exercise to ensure that procedures exist which meetsome minimum, but undefined, standards. Except
for the resident inspector program, considerable inspection effort is devoted to document audits and to
determining whether procedural requirements arebeing observed.
The inspectors are the NRC's observers during
the power ascension tests, acceptance, and preoperational testing programs. The confidence thatstructures, systems, and components will perform
as required is a strong function of the adequacy ofthese programs, second only to how well they were
designed, constructed, or fabricated in the firstplace.
Practically no standards have beendeveloped in this area, however, and the basis fordetermining the amount of inspection resources all ocated to different activities, such as the relative
risks for the various activities, is not well defined. 91
The NRC's Inspection and Enforcement Manual
identifies the purpose of the inspection program forthe operations phase of nuclear power reactors to
be "to obtain sufficient information through direct
observations, personnel interviews, and review offacility records and procedures to ascertain whether
the licensed management control program is effective and whether the facility is being operated safely
92
i n conformance with regulatory requirements."
I nadequate capabilities for data analysis and for independent verification impairs theachievement of93
the overall goals of this program.

I nspection and Enforcement

The inspection process is performed primarily byobservation of licensee activities, visual inspectionof hardware, and audit of records to ascertain
whether the licensee is complying with applicableregulatory requirements and commitments (seeSection I.B.3). The audit of documents is relied onheavily to verify compliance with quality assurance
requirements. The inspection process is guided byprocedures, or modules as they are called, contained in the Inspection Manual, the inspectors'
analogue to the Standard Review Plan for the NRRtechnical reviewers of the application. The procedures relating to risk mitigating systems are generally grouped by categories used in the standard

There Is No Provision for Systematic Evaluation of
Operating Reactor Experience and Related
Research

The NRC's extensive reporting system, Licensee
Event Report System (LERS), gathers substantial information on the operating experience at nuclear
19ity for making the ultimate safety finds are madeaware of, but powerless to deal with, a long list ofgeneric issues awaiting resolution, some of whichhave remained outstanding for a long time. As amatter of regulatory practice, generic issues related
to a particular plant are not required to be resolved
prior to that plant's licensing. Thus, by being labelled generic, these issues cease to be obstacles
to the licensing of specific plants. This general policy is designed to avoid undue delay in the licensing
process, and to provide an element of stability inthat process by assuring that issues of general applicability are resolved on a consistent and uniform
basis from one plant to the next. One of the regulatory premises underlying the categorization of an issue as generic is that its safety significance does
not prohibit the continued operation of the plant
95
Generally, thiswhile the issue is being resolved.
premise does not receive the scrutiny it deserves,
however. Categorization of issues as generic also
assured that they would be resolved, if at all, either
without public participation, or if a regulation changeor addition were involved, probably on the basis of
an informal rulemaking proceeding. Because thesei ssues were not deterrents to the licensing ofspecific plants, there was no incentive for priority
attention to be given to their resolution. An examination of the numerous issues categorized as generic, however, calls that premise into serious question.
Eventually, a series of events stimulated increased staff attention to this problem. In 1976,
members of the NRC's technical review staff raised
27 generic safety issues, and in 1977, the NRC instituted a program to impose management control in
the area.
On November 23, 1977, the ASLAB emphasizedthat "unresolved" issues cannot be disregarded ini ndividual licensing proceedings simply ly because
they also have generic applicability.
The board
indicated that there must be some explanation in the
Safety Evaluation Report why construction shouldbe allowed to proceed in the face of an unresolved
generic question. The appeal board later held that
where operation of a reactor is involved, the justification for authorizing the license in light of unresolved generic issues can obviously be more diffi97
cult than at the construction stage.
On December 13, 1977, the Energy Reorganization Act of 1974 was amended to include a new98
Section 210, "Unresolved Safety Issues Plan."This statute directs the NRC to develop a plan "providing for specification and analysis of unresolved
safety issues relating to nuclear reactors," and topowerplants. In addition, the NRC's operational database includes input from inspection and enforcement reports, the reporting of defects, noncompliance, construction deficiencies, and some information from foreign reactors. 94
Even though a major purpose of obtaining this information is to identify potential safety-related probl ems, prior to March 1979, the NRC never established a procedure to assure that operating information is systematically analyzed and evaluated forits safety significance. To the extent that operating
experience was reviewed, reviews were conducted
on a random, uncoordinated basis with no assurance that major safety-related problems werei dentified, or that related information was dissemi nated to the industry and fed back into the licensing
and regulation process for reactors. No attempt
was made by the NRC to require the industry to
conduct such evaluations, and the NRC did not inform the industry of the limitations of its own analyti cal and evaluation efforts. Similarly, it is uncertain
to what extent the large number of technical reports
developed in research programs that possess potential safety significance are routinely considered
and injected into the regulatory system.
The NRC's efforts to impose requirements fori nformation exchange within the industry are equally
deficient. The nuclear industry has a system,
Nuclear Plant Reliability Data System (NPRDS), forvoluntarily reporting minor mishaps and components
failures at operating nuclear powerplants. In his
April 1977 energy message, the President of theUnited States requested the NRC to make that system mandatory. The NRC has not yet decided
whether the benefits from a mandatory system
would outweigh the additional industry burden, however, and consequently has not acted.
The "Generic" Label Is Used to Prolong the
Resolution of Safety Issues"Generic safety issues" are issues related to aparticular class or type of reactor plant or design,and not just to a specific plant (see Section I.A.3.c).
They are also referred to as "unresolved safety issues," although not all generic issues are related tosafety matters. Until recently neither the NRC nor
its predecessor made an attempt to define, categori ze, or manage generic technical activities on a systematic basis. Even now, progress in this regard isdisappointing.
The dichotomy between generic and plant specific safety issues leads to situations in which Atomic
Safety and Licensing Boards having the responsibil-

20

10 C.F.R. Part 50-Domestic Licensing oftake such action "as may be necessary to implement corrective measures with respect to such issues." Section 210 required the NRC to submit toCongress on January 1, 1978, a report on its plan for
the resolution of generic issues. One feature of thesubmitted plan was a Technical Activities Steering
whose purpose is to increase manageCommittee, involvement in and oversight of, generic technment activities. Unfortunately, the NRC's actual progress in this area has been disappointing. With allof these stimuli, the NRC has reported some progress regarding the schedules and priorities for the
resolution of these issues on the basis of their contribution to risk. 99 Criteria for identifying such items
as the priorities for resolution of these issues, fordetermining when to allow construction and operation of a reactor even though outstanding unresolved generic safety issues remain, or for otherwise governing the activities of the Technical Activities Steering Committee remain either vague ornonexistent, however.

Production and Utilization Facilities: Appendix A," General Design Criteria for Nuclear Powerplants"

The development of General Design Criteria
GDC)
for nuclear powerplant construction permit(
applications began in 1964. The GDC were first issued for interim guidance in 1965, and were reissued in 1967. Following extensive discussion withi ndustry representatives, 55 criteria were publishedas mandatory requirements in Appendix A to Part
50, which became effective on March 21, 1971. In
the introduction to these criteria, the following statement is made:The development of these General Design Criteria
i s not yet complete. For example, some of the definitions need further amplification. Also, some ofthe specific design requirements for structures,
systems, and components important to safety havenot as yet been suitably defined.

These general criteria have remained essentially unchanged since that statement was made in 1971,
and they have not been significantly changed since1967. Moreover, the GDC constitute only generalstatements of design objectives or principles. The
criteria lack any explanation of their underlying logic
or discussion of their interrelationships.
Thisshortcoming provides each staff reviewer little guidance when left with the task of deciding what thegeneral words mean, what assumptions need to be103
made, and how the GDC should be applied.

Some Important Regulations Are Inadequate

The NRC's regulations, like the focus of thestaff's review, mostly set forth general criteria relati ng to design. The regulations are almost completel y lacking in any criteria relating to the operational
aspects of nuclear reactor safety. Moreover, theregulations do not contain well defined safety criteria and requirements. Many are ineptly draftedsome to the point of being virtually incomprehensible. Others appear to be of questionable merit inview of the changes that have occurred since their
publication.100Still other regulations have quite obvious gaps.
No organizational entity is charged
specifically with the responsibility of assuring thatthe regulations are adequate, or alerting the NRC toproblems in the regulations themselves. Some of
the more significant examples of inadequacies in the
NRC regulations follow.

10 C.F.R. 50.109-"Back fitting" Regulation

These regulations provide in part that:

The Commission may ... require the backfitting of a
facility if it finds that such action will provide substantial, additional protection which is required forthe public health and safety or the common defense and security.

Prior to release of this regulation in March 1970, thei mposition of additional safety requirements after theissuance of a construction permit, commonly referred to as "backfitting," was handled on a caseby-case basis. In the more than 9 years that followed issuance of the backfitting regulation, thesedecisions continue
to be made without workable104
backfitting criteria(see Section I.A.3.a).

10 C.F.R. Part 100-Reactor Site Criteria

The essential elements of nuclear powerplant siting policy are set forth in Part 100. These regulations were published by the Atomic Energy Commission in 1962 as an "interim guide." The authors
recognized that experience with siting nuclear
powerplants was at that time too limited to form thebasis for a more definitive final statement. 101
Nevertheless, these 1962 "interim" regulations102
have
not been significantly changed since that time.

10 C.F.R. 50.35-Issuance of Construction Permits

The proposed "backfitting" regulation included a
provision for development and use during reactor
construction of a system similar to the technicalspecification system used for reactor operation.

21

This proposal was not adopted in the final rule,
however. The reason given was that the "essential
elements of the proposal design" in the proposed
rule "require further definition involving additional
05
study.""
After 9 years of further study the regulations still have not been clarified in this area.
Nevertheless, every construction permit contains
l anguage authorizing construction of the proposed
facility "in accordance with the principal architectural and engineering criteria." Although subtle legal
arguments can be made to give these words meani ng, the technical reviewers lack any regulatory definition. Consequently, even though a quarter of acentury has passed since the enactment of theAtomic Energy Act of 1954, there are no clear regul atory criteria as to the meaning of a construction
permit, or the extent to which a construction permit
holder may make changes of the plant design proposed in the application without prior NRC approval.
Similarly, there are no workable regulatory criteria
for the staff to follow in determining whether to require reactor "backfitting" after a construction permit has been issued.

cess. The interpretation of NEPA by the U.S. Courtof Appeals for the District of Columbia in Calvert

Cliffs Coordinating Committee v. United States
Atomic Energy Commission, 449 F. 20 1109 (D.C.

Cir. 1971), substantially magnified NEPA's impact on
the licensing process. Among other things, the Calvert Cliffs decision required the cost-benefit
balancing of a potentially vast number of environmental values. As a result, issues such as the needfor power, choices of fuel and alternative sites, andthe availability of uranium resources, now are raised
in individual licensing cases. These must be
evaluated, along with innumerable other environmental issues raised in the draft and the final environmental impact statements, for each plant at theconstruction permit and operating license stages.
These new demands began during 1971 to 1974, a
period when other events that had a substantial impact on the licensing process occurred, such as the
beginning of opposition to the location of nuclear
powerplants and the increased number of new applications for both construction permits and operating licenses, with the resulting increased demands
on staff resources. (See Table I-1.)
During these years a continuing increase in thesize of the technical staff occurred. Although thisinquiry has not attempted to quantify the degree of
the impact of Calvert Cliffs, the fact that a number ofsenior personnel who were trained and who worked
in the field of nuclear reactor safety were permanently transferred to work in the environmental
impact statement field suggests that it may havebeen significant.
Substantial prelicensing antitrust review responsibilities were also added to the system for theli censing of nuclear powerplants in the 1970 amendments to the Atomic Energy Act of 1954, including
Public Law 91-560, 84 Stat., 1472. Although thislaw added to the overall licensing effort, it did not
require that staff resources be diverted from nuclear
safety review work, as did the Calvert Cliffs decision. On the other hand, the law imposes responsibilities on the NRC that are not at all related to theCommission's
primary
responsibility
andcapability-protection of the public health and safety from nuclear radiological hazards.
The Nuclear Nonproliferation Act of 1977 109 substantially extended the NRC's nuclear export
responsibilities. The expansion by this complex andin part, inscrutable law, was not in the area of radiological health and safety, however. Although the
NRC has little or no public health and safety responsibility for nuclear exports, the Nuclear Nonproliferation Act of 1977 requires its involvement in foreign
nuclear commerce, nuclear weapons nonproliferation, foreign policy determinations, and other similar

10 C.F.R. Part 21-Reporting of Defects and NoncomplianceThis regulation is ambiguous regarding importantmatters, such as its applicability to architectengineers and to information originating from experience with a reactor located outside of the UnitedStates.

Proposed Annex to Appendix D to 10 C.FR Part 50

Proposed by the Atomic Energy Commission
nearly a decade ago, this annex, although never officially adopted, has been followed as guidance eversince. The annex establishes classes of accidents,
i ncluding the "Class 9," which is beyond the designbasis spectrum of accidents. More importantly, its
effect is that the consequences of such accidents
are not considered in the environmental statements
for land-based nuclear plants. 107
The System Is Tasked with Major Responsibilities
Other Than Nuclear Reactor Safety

The National Environmental Policy Act (NEPA), 1
which took effect on January 1, 1970, required that
nonradiological effects on the environment be considered in the licensing of nuclear power reactors.
Theretofore, licensing jurisdiction was confined toradiological safety. Even under a begrudging interpretation, NEPA's extension of jurisdiction would
have had a substantial effect on the licensing pro22

TABLE I-1. Applications received during fiscal years 1967-75
Construction Permit
Applications

Number of
Number of
Fiscal Year
Applications
Units------------------------- - ----------------1 967
16
22
1 968
18
24
1 969
14
19
1 970
7
12
11
16
1 971
1 972
5
10
1 973
9
17
1 974
21
42
1 975
14
31

areas. These are all areas which, in large measure, the NRC is neither designed nor staffed to handle and which appear to be ill-suited for an independent regulatory body. During the first year of thisAct's existence, which incidentally ended shortly
before the TMI-2 accident, the NRC devoted a substantial portion of its time to these international
matters.110

Operating License
Applications

Number ofApplications
3
3
8
6
15
2
7
5
1

Number of
Units
3
4
13
7
22
3
9
8
1

d. Findings and Recommendations
Findings• The Atomic Energy Act of 1954, as amended, andthe Energy Reorganization Act of 1974, as
amended, authorize the NRC to act with almost
unlimited discretion in making substantive publichealth and safety, and common defense andsecurity judgments, provided that the minimumprescribed procedures, essentially legal, are observed.
• There is a lack of policy direction and guidancefrom the NRC to the staff. The system does nothave well defined regulatory objectives, and no"Acceptable Risk" goal has been established aspolicy.
• There is no regulatory yardstick either to measure existing risk, to evaluate the effectiveness ofregulatory actions in decreasing risks to an acceptable level, or to assure that an acceptablerisk level is maintained.
• For more than two decades, the NRC and its
predecessor have licensed nuclear powerplants
almost exclusively on the basis of engineering
judgment.
• There is no yardstick, other than the safety
record of operating plants, by which anyone canrationally evaluate either the quality or the consistency of these highly personalized judgments,or the degree of assurance of safety they provide.
• Although the NRC has broad rulemaking authority, its regulations are in many respects outdated
and inadequate, as noted by its appeal board andothers.
• Responsibility for substantive safety matters is
fragmented within the NRC among five major offices, and is further diffused at and below the

The System Promised More Than It Delivered

Over the years the system has been portrayed
as one that deals with substantially more from a regulatory standpoint than it in fact does. For example, the entire area of plant operations-technicalqualifications of the utility, personnel qualifications,operating and emergency procedures, and humanfactors-have received only superficial attention
from the regulatory standpoint. This lack of attention, when coupled with fragmented safety-related
responsibilities within the industry, could well havel ed to an excessive reliance on the NRC by utilities
and others in the industry.
The present organization and vague standards
almost assure that the licensing system will have
deficiencies. The existing highly fragmented operation, the absence of an entity outside of the licensi ng and regulatory system to observe and evaluate
its quality, and the broad discretion typically exercised at almost every review level, fosters divisiveand parochial interests rather than a coherent regul atory system. Coupled with the almost total emphasis on the regulatory system's efficiency (i.e.
"promptness") rather than its quality, theseshortcomings lay the groundwork for a system that
does not focus on the difficult issues and which, inthe final analysis, does not offer the public the highquality licensing and regulatory system to which it isentitled.
23

•
•
•

•

•

•

•
•
•
•

• After licensing, no regulatory criteria exist thatdivision level within these offices, particularly in
the Office of Nuclear Reactor Regulation.
There is no unified and positive leadership ormanagement of the internal operation of the NRC.
The NRC does not operate as a team working together to identify and resolve difficult issues. Instead, there is an excessive and detrimental
amount of parochialism.
The NRC and its staff have almost unlimited discretion in making safety judgments provided certain ASLB findings are made. These findings canbe made almost ritualistically on the basis ofpoorly articulated engineering judgment.
The system focuses almost entirely on nuclear
systems and equipment, and practically ignoresoperational areas (e.g., qualifications of utilities,
procedures, systematic evaluation of operational
information, human engineering, etc.). The focus
on design and equipment is evident in the composition and qualifications of the regulatory staff,
which is not operations oriented or experienced.
Important participants in safety decisions (reactor
system vendors and architect-engineers) are almost completely isolated from the regulatory system, except for quality assurance and deficiency
purposes, although they are affected by, and may
react to, the requirements the system imposeson licenses.
The system does not assure that significant safety issues are identified through risk assessment
methods and techniques. For example, the Standard Review Plan is not based on risk assessment methods, there is little focus on things suchas systems interactions, safety/nonsafety grade,single failure criterion, design basis accident
bounds, etc.
The system provides no incentives to enhancesafety; instead it results in acceptance of what
may be the "lowest common denominator," compliance with NRC requirements.
The system does not deal adequately with thedisincentives to safety such as who will bear the
economic burden if safety improvements arerecommended and adopted.
The system does not encourage and is not receptive to the ideas and suggestions of others.
The licensing system now permits, and indeed
encourages the commencement of a massive
construction effort on the basis of preliminary
design information (e.g., the two step licensing
process, limited work authorization, and the immediate effectiveness rule). It also provides discincentives to desired regulatory goals, such as
the move in the direction of standardization.

•
•

•

•

can be applied to explain on a rational basis
things such as the imposition of new regulatory
requirements, enforcement actions, and postlicensing actions such as "administrative solutions"to a design flaw. This entire area is one where
actions appear to be based almost completely on
the judgment of senior staff officials.
NEPA and its judicial interpretations have placed
significant responsibilities on the NRC in areas
other than reactor safety.
The Congress, in the Atomic Energy Act of 1954,
as amended, has placed prelicensing antitrust review responsibilities on the NRC, which have little
or no relation to the Commission's primary radiological health and safety mission in the nuclear
field.
The Congress in the Nuclear Nonproliferation Act
of 1977, has placed substantial international relations responsibilities on the NRC. These responsibilities have little or no relation to the NRC's primary reason for being and, it would appear, arei nappropriate for an agency outside of the Executive Branch.
I n the absence of national policies on societal
risks from available means of generating electricity and the fuel choices which should be made,these issues are being debated by interested
members of the public in the licensing of individual nuclear powerplants.

Recommendations• A Nuclear Reactor Safety Board should be esta-

blished outside the line functions for licensing andregulation that would, among other things, exercise independent oversight of the effectiveness ofthe system. Another component of this oversightorganization should be an Office of Public Counsel. Core of the internal oversight team: ACRS
(independent and advisory); Reactor Safety
Board; and Office of Public Counsel.
• A statement of regulatory objectives should be
developed including policy on risk objectives andmethods, to better use risk assessment techniques either qualitatively or quantitatively, inlicensing and regulatory actions. The importanceof WASH-1400 techniques should be emphasized
through an expanded risk assessment programthat provides some of the evaluative tools todetermine the qualitative or quantitative relativerisk significance of events or patterns of events.
• I mportant participants in nuclear plant design and

24

•
•

•
•

li censing operation, or permitting of continued
operation with major open safety issues should
be examined and prompt action taken to publish
applicable regulatory criteria. Judgment needs tobe exercised, but on a rational regulatory basis
bounded by criteria based on the best available
relative risk assessment.
• The NRC should be relieved of all responsibilities
placed on it under the Nuclear Nonproliferation
Act of 1977. These functions should betransferred to the Executive Branch.
• The NRC should be relieved of its prelicensing
antitrust review responsibilities under the Atomic
Energy Act of 1954, as amended. These responsibilities should be transferred to the Executive
Branch.
• The U.S. Government, after considering and comparing societal risks from presently available
means of generating electricity, should decide on
the choices to be made as a matter of national
policy.

construction, such as the reactor system vendors
and the architect-engineer, should either beli censed or made accountable by someequivalent system.
An organization should be designated to haveprimary responsibility in the rulemaking area toassure that the quality of the regulations are adequate.
The two-step licensing process as it is now
used, should be abolished along with other policies (limited work authorizations and the immediate effectiveness rule), and replaced with a system that provides incentives for more design andsite-related safety and environmental issues tobe resolved before construction begins.
Incentives should be established that would resultin more information prior to construction, fewer
unresolved issues, and less variety in the designof important systems.
Important areas such as the backfitting of new
regulatory requirements, enforcement actions,25

REFERENCES AND NOTES
44'The terms utility, licensee and applicant will be usedinterchangeably throughout.
2
Nuclear powerplant licensees are subject to prelicensing antitrust review requirements in Section 105 of
the Atomic Energy Act, 42 U.S.C. 2135.

It might be noted in passing that large nuclear units
may involve many utilities as licensees. Typically, one
utility assumes the "lead role" and will be the operating
utility. Although Commission regulations do not distinguish between the operating holder of an operating
license and the other utilities which are also technicallylicensees, in past cases the NRC has granted the operati ng utility a license to operate the nuclear facility and topossess nuclear materials. The other participating utilities
are identified in the license as simply holding a license topossess
nuclear materials.
45
10 C.F.R. Part 21.
48
42 U.S.C. Sec. 5846.
47
10 C.F.R. Part 50, Appendix B.
These memoranda of understanding deal with relations between numerous agencies. Examples include
those reached with the Environmental Protection Agency(40 F. Reg. 60115, December 23,1975; 38 F. Reg. 24936,
August 21,1972); the Department of Transportation (38 F.
Reg. 8466) and the Army Corps of Engineers (40 F. Reg.
37110, August 25, 1975).
49
1 n emergency response planning, the EPA has
assumed many of the responsibilities of the former
Federal Radiation Council and in that capacity has beenreviewing the Federal Radiation Protection Guides (25F. Reg. 4402, May 18, 1960). The NRC and other member
agencies of the Federal Interagency Coordinating Committee for Emergency Preparedness have commented to
the EPA on proposed nuclear accident protective guides
for airborne releases of radioactive gases and particulates. These guides, which are being prepared for use by
State and Federal agencies in emergencies, will become
part of NRC regulations once promulgated by EPA.
50
OSHA defers to the NRC on matters of radiologicalhealth and safety, and NRC licensees are deemed incompliance with OSHA regulations by the Department ofLabor.
51
Northern State Power Co. v. Minnesota, 405 U.S.
1035 (1972).
52
The NRC has offered the States planning guidanceon developing emergency plans [See NUREG 75/111(1974)] and responding to various types of accidents( NUREG-0396). The NRC has also trained State emergency response personnel in courses taught by various
Federal agencies. Examples of courses which have been
available include "Radiological Emergency Response
Planning." This training is available to all States' personnel, not just those with plans that are concurred with by
the Commission.
53
See General Accounting Office Report EMD-78-10,"Areas Around Nuclear Facilities Should Be Better
Prepared for Radiological Emergencies," March 30, 1979.
It should be noted that the absence of a State approved
plan as of March 28, 1979, does not preclude a utility's
operating a plant there. The NRC did not, as of thatdate, require that each State with a nuclear plant have anapproved plan, although the licensee's emergency plan, inpart, relied on State and local agencies.
54
See e.g., "Licensing and Regulation of Nuclear Reactors," Hearings before the Joint Committee on Atomic
Energy, Part 1, 90th Cong., Ist Sess., 2-227 (April, May
1967); "Nuclear Reactor Safety," Hearings before the3Power Reactor Development Co. v. International
Union of Electric Radio and Machine Workers, 367 U.S.

396 (1969).
4Some preliminary work, such as site clearance, ispermitted under a Limited Work Authorization, however.
10 C.F.R. Sec. 50.10(e).
542 U.S.C. 2131, 2235.
6
10 C.F.R. Sec. 50.10(b).
7
10 C.F.R. Secs. 50.51, 50.57.
B
See 10 C.F.R. Part 50, Appendix A.
9Petition for Remedial and Emergency Action, 7 NRC
400, 418 (1978).
1011 See 10 C.F.R. Sec. 50.34.
10 C.F.R. Part 100; Part 50, Appendix B.
1210 C.F.R. Sec. 50.30(f); 10 C.F.R. Part 51.
13
14 10 C.F.R. Sec. 50.33A.
10 C.F.R. Sec. 2.102.
15
42 U.S.C. Sec. 4321 et seq.
16
42 U.S.C. Sec. 2239a.
17
10 C.F.R. Sec. 50.58(a).
18
10 C.F.R. Part 2, Appendix A.
19
10
C.F.R. Sec. 2.760(a).
20
10 C.F.R. Secs. 2.714(a)(1); 2.715(a),(c).
21
10 C.F.R. Sec. 2.758(b).
22The steady increase i n the number of contested
hearings during this decade is documented in the NRC's
Annual Report to the Congress. Each of these reports
i ncludestatistics on the subject.
23
10 C.F.R. Secs. 2.760, 2.762, 2.764(a), 2.785,
2.785(b)(2),2.785(c), 2.786, 2.786(a)(b), 2.786(b)(4).
24
42
U.S.C.
Sec. 2232b.
25
10 C.F.R. Secs. 50.55(e), 50.35, 50.91.
26
However, "generic" unresolved safety issues may
remainoutstanding at this point.
27
10 C.F.R. Sec. 50.36(c).
2842 U.S.C. 2232a.
29
10 C.F.R. Secs. 50.58(b), 2.105, 2.714.
30
10 C.F.R. Sec. 50.35(a).
31
42 U.S.C. 2077c(2).
3210 C.F.R. Secs. 50.35(b), 50.34(b).
33
See 42 U.S.C. Sec. 2235.
34
See 10 C.F.R. Sec. 50.57.
35
10 C.F.R. Sec. 50.51.
38
42 U.S.C. Sec. 2236.
37
10 C.F.R. Subpart B.
38
See "backfitting," 10 C.F.R. Sec. 50.109.
39See "backfitting," 42 U.S.C. Sec. 2233.
40
10 C.F.R. Sec. 50.54W.
42

10 C.F.R. Secs. 50.70, 50.71.

4310 C_F.R. Sec. 2.202.

26

Joint Committee on Atomic Energy, Part 1, 93rd Cong., 1stSess., (January, September, October, 1973); and "Nuclear
Regulatory Commission's Safety and Licensing Procedures," Hearing before the Committee on Government
Operations, U.S. Senate, 94th Cong., 2d Sess.
( December 13, 1976).
55"NRC Statement on Risk Assessment and the Reactor Safety Study Report (WASH-1400) in Light of the Risk
Assessment Review Group Report," January 18, 1979.
This statement is published in "Reactor Safety Study
Review," Oversight Hearing Before the Subcommittee on
Energy and the Environment of the Committee on Interior
and Insular Affairs, House of Representatives, 96th Cong.,
1st Sess., 115 (February 26, 1979). This document will be
subsequently cited as "Reactor Safety Study Review."
56
See Memoranda from Commissioner Gilinsky toother Commissioners, "Commission Statement on theReactor Safety Study," January 22, 1979; from Chairman
Hendrie, "Commission Statement on Nuclear Plant
Safety," January 25 and 31, 1979; and from Commissioner Ahearne to Joseph Fouchard, "Commission Statement on Reactor Licensing," February 6,1979.
57"Reactor Safety Study Review, (at p. 4)", Oversight
Hearing before the Subcommittee on Energy and theEnvironment of the Committee on Interior and Insular
Affairs, House of Representatives, 96th Cong., 1st Sess.,
115 (February 26, 1979).
58
1d. at 90-114 of Prepared Testimony, 4-29 of Oral
Testimony59
42 U.S.C. Sec. 2039 (Section 29 of the Atomic
Energy Act).

Process for Nuk m Power Plants," NUREG-0545, at 76,
June 1978.
67
10 C.F.R. Sec. 2.780.
6
OHanauer dep., Exhibit 1134.
69
42 U.S.C. Sec. 2201i.
70
See Petition for Remedial and Emergency Action, 7
NRC 400 (April 13,1978).
71
It was not until September 1, 1978 that the Commission noted the following as requiring "further action by thestaff" (Memorandum from Samuel J. Chilk, Secretary to
the Commission, to Lee V. Gossick, Executive Director
for Operations, "Improving the Process for Determining
the Need for New Reactor Requirements ...," September
1,1978):• How might the staff most expeditiously proceed to•••sThe Atomic Energy Act, Pub. L. No. 95-209, 91 Stat.,1483 (1977).

•

1f the application for a license to construct is
opposed, as most have been during the 1970s by intervening parties, the ASLB must make all of the required
safety findings and authorize the Director of the Office of
Nuclear Reactor Regulation (NRR) to issue the construction permit. If the application is not contested, the
ASLB's role is to decide "whether the application and therecord of the proceeding contain sufficient information,"
and whether the staff's review "has been adequate tosupport the Director of the Office of Nuclear Reactor
Regulation's proposed findings for the issuance of theconstruction permit" (10 C.F.R. Part 2, Appendix A V (f)and 2.104).
ASLBs also conduct the hearings on application for ali cense to operate nuclear power reactor, if a hearing isheld. I n an operating license proceeding, the ASLB
determines the contested issues. The director of NRR,
depending on the ASLB's resolution of the contested
issues, would issue, deny, or appropriately condition theoperating license [10 C.F.R. Part 2, Appendix A VIII (b)(c),2.104(c)].
62
42 U.S.C. Secs. 2239a, 2241 (Sections 189a, 191 of
The Atomic Energy Act).
63
See 10 C.F.R. Sec. 2.785(a).
84
10 C.F.R. Sec. 2.786(b)(1).
65Even if there is no appeal, the ASLAB reviews the
ASLB's decision. Any action taken by an ASLAB "shallhave the same force and effect ... as actions of the Commission" subject, however, to review by the Commission[10 C.F.R. Secs. 2.785(c), 2.786(a)].
61

66

•

•
•

•

define in more explicit-if not quantitative-terms thecriteria for deciding when a requirement is essential tosafety, while still recognizing that judgment is an
inherent part of such decisions?
What needs to be done to clarify the circumstances
under which economic impacts associated with new
requirements can and should be taken into accountand to improve the quality of value-impact analysis of
new requirements?
How should NRR decisions and the basis for new
requirements best be documented and most expeditiously communicated to and implemented by thoseaffected?
How can the NRR process be opened to observationor participation by interested persons outside so as toi mprove the quaky of new requirements and the timeliness of their implementation?
Might RRRC (Regulatory Requirements Review Committee) membership and structure be altered to more
appropriately account for the extent of demands on
the time of senior staff personnel and the possibility ofconflicts with their other duties?
What changes in NRR procedure might be adopted
which would take better account of the concern thatthe precedent established by imposing new requirements in individual cases in the interim, prior to RRRC
review and approval (so-called category 4) make
RRRC approval and NRR adoption for generic use aforegone conclusion?
How might NRR procedures be improved to preventthe further accumulation of generic issues and to
introduce greater predictability with respect to requirements to be imposed?
What might be done to better distinguish the basis for
permitting a licensed reactor to continue operation
pending implementation of a new requirement,
whereas the operating license for a completed reactor
may be withheld until the new requirement has been
incorporated?
How might NRR identify and eliminate elements of theStandard Review Plan, which make an insignificant
contribution to overall plant safety, so that staff andi ndustry resources can be focused on matters of mostsignificance to safety?

The staff responded to the September 1, 1978
memorandum in an "Information Report" to the Commissioners, SECY-79-8, "Improving the Process for Determining the Need for New Reactor Requirements," January
2, 1979. However, as of March 1979, with one exception

See NRC, "Seminar Report on the Public Hearing

27

gram and the inspection and enforcement reports it produces in identifying safety issues and in reducing reactor
risk. The Division of Inspection and Enforcement itself
apparently has been searching for an approach in thisarea. See, e.g., "Licensee Performance Evaluation,"
NUREG/CRO110 (Phase I), October 1978; "Licensee Performance Evaluation ( Phase III), NUREG/CR-0979,
August, 1979; Draft Report to IE by Teknekron Inc.,"Analysis of the First Eighteen Months of Licensed
Operations of Babcock and Wilcox Plants," September,
1979; and "Insights into Improving the Efficacy of Nuclear
Power Plant Inspection Procedures Based upon Risk
Analysis," NUREG/CR-0153, BMI-2004, June, 1978.
94
Whether information from foreign reactors is evenreceived apparently depends, in large measure, on agreements between our Government and the country in which
the reactor is located. In some cases, this information
may never be received by our Government. Moreover,even if the information is provided, its dissemination to
the public may be subject to constraints imposed by theagreement between the United States and the foreigncountry. Insisting that the constraints be removed may
result in no information being received at all, however.
95
NRR, "Identification of Unresolved Safety Issues
Relating to Nuclear Power Plants," NUREG-0510, at 4,
January 1979.
986 NRC 760.
97
8 NRC 245. The reason often given for allowing
construction to proceed is that there is time to find asolution and build it into the plant's design. Thereafter,
the most common reasons for allowing a reactor tooperate, even though there are unresolved generic safetyissues, are that a solution satisfactory for that reactor has
been imposed, that a restriction on the level or nature ofoperation adequate to eliminate the problem has been
i mposed, or that the issue does not arise until the later
years of plant operation.
98
The Energy Reorganization Act, Pub. L. No. 95-209,
91 Stat., 1482 (1977).
99
See NUREG 0410, January 1978 and NUREG 0510,
January 1979.
10
DMalsch dep. at 10-14,139-141.
101"Insufficient experience has been accumulated topermit the writing of detailed standards that would provide a quantitative correlation of all factors significant to
the question of the acceptability of reactor sites. Thispart is intended as an interim guide to identify a numberof factors considered by the Commission in the evaluation of reactor sites and the general criteria used at thistime as guides in approving or disapproving sites."
102
See, NRC, "Report of the Siting Policy Task Force,"
NUREG-0625,
August, 1979.
103
Some guidance is available in the Standard Review
Plan and Regulatory Guides, but the General Design Criteria are so general that they provide a basis for a variety
of interpretations that may change with time.
Case dep. at 235-236.
105
NRC, Federal Register, Vol. 35, No. 5317, March 17,
1970.
108
Angeb dep., Exhibits 1073-1078.
107
See, NRC, Federal Register, Vol. 36, No. 22851,
December 1, 1971. See also Offshore Power Systems(Floating Nuclear Plants) ALAB-489, 8 NRC 194 (1978),(opportunity to receive views of interested persons),
these items had not been acted upon by the NRC.
72
NRC, "Reactor Safety Study-An Assessment of
Accident Risks in U.S. Commercial Nuclear Powerplants,"
Executive Summary, Wash-1400 (NUREG-75/014),
October 1975.
73( SECY-79-106): Memorandum from H. R. Denton,
NRC, to the Commissioners, "Review of Use of WASH1400
in Licensing Actions," February 9,1979.
74"The Lewis Report," NUREG/CR-0400, September
1978,
Page xi.
75
See "Federal Regulation and Regulatory Report,"
Report by the Subcommittee on Oversight and Investigations of the House Committee on Interstate and Foreign
Commerce, 94th Cong., 2d Sess., Page 515 (October,1976). Compare Case dep. at 227-229 and Staff Paper,
SECY-79-424,"Value-Impact Guidelines," (July 2,1979).
76
DPM was once the place in the organization where
the entire plant was reviewed. The project manager then
was the "Systems Interactions" reviewer. That role is no
performed in DPM. however.
longer77
Presumably, the transfers are not accepted by the
DOR if, in the judgment of its management, a large
number of safety issues remain unresolved. See also
Vassallo dep. at 35-44 and Case dep. at 245-246.
78
Ross dep. at 94 and Exhibit 1158.
79
NRC Office of Inspector and Auditor, "Independent
Review of the Browns Ferry Fire," NR 01A-001, at 17,
August1976
80
Case dep. at 242.
81
Examples of delayed implementation of the committee include Regulatory Guide 1.101 on emergency planningand Regulatory Guide 1.97 on instrumentation to monitor
the course of an accident.
82
See 10 C.F.R. Part 50, Appendix K-ECCS Evaluation Models.
83
Hanauer dep. at 59-62.
84
See proposed annex to 10 C.F.R. Part 50, Appendix
D- NRC, Federal Register, Vol. 36, No. 22851, December
1, 1971.
85
Hanauer dep. at 110-115.
8eA practical working definition is that an item is"safety-related" if its failure can lead to the release ofradioactivity or if it is needed to mitigate the consequences of an accident.
87
Vassallo dep. at 25.
88

See Report of the General Accounting Office"Nuclear Power Plant Licensing: Need for Additional
I mprovements," EMD-78-29, page 22, April 26, 1978.
89

See generally, NRC, "Nuclear Power Plant Licensing:Opportunities for Improvement," NUREG-0292, at 1-3, 211-12, June 1977.
90

See Angelo dep. and attached Exhibits.

See generally, NRC, "Insights into Improving the Efficacy of Nuclear Power Plant Inspection Procedures
Based upon Risk Analysis," NUREG/CR-0153, June 1978.

92 Inspection and Enforcement, U.S. Nuclear Regulatory Commission, Office of Inspection and Enforcement,
Chapter 2500.

salt is difficult, under these circumstances, to evaluate
the measure of the effectiveness of the inspection pro28

See The Nuclear Nonproliferation Act, Pub. L. No.
95-242, 92 Stat., 120 (1978).
n°See "Does the Emperor Have Any Clothes," aspeech by Chairman Ahearne (then Commissioner), September 11, 1979.

reconsideration denied and cert. granted, ALAB-500, 8
NRC 323 (1978)). See also Carolina Environmental Study
Group v. A.E.C, 510F.2d796, 798, 799 (D.C. Cir. 1975).
See The National Environmental Policy Act, Pub. L.
No. 91-190, 83 Stat., 852 (1970).

29the steam generator. Requirements for hydrostatic
testing are set forth in Appendix G to 10 C.F.R. Part
50. Appendix G does not, however, address testing
conditions when fuel is loaded in the reactor vessel.
Conformance to the technical specifications would
have delayed the test until the unit had achieved
operational mode 4 (hot shutdown) thereby allowing
the reactor coolant conditions to meet the pressure
and temperature requirements. The staff's safety
analysis concluded that the fuel would not be subjected to conditions that might damage the fuel, andthe testing was completed with the fuel in the7vessel

2. RELEVANT REGULATORY STAFF ACTIONSTAKEN OUTSIDE OF THE ADJUDICATORYPROCESSa. Issuance of Operating License
The operating license for TMI-2 was issued on
February 8, 1978. 1 Attachment 1 to the license included the technical specifications that delineatedthe operational requirements and limits for the facility. Attachment 2 contained a number of preoperational tests, startup tests, and other requirementsthat required completion by the licensee. The TMI-2
license contained a number of license conditions
that required completion at some specific event ortime, or at the outcome of some evaluation orproceedings.
The license was issued on the basis of theevaluation and approval of the Final Safety Analysis
Report docketed in 1974 (including 62 amendments
to the Report) and the environmental report as supplemented and amended (see Section I.B.1). The
TMI-2 license application was managed by Light
Water Reactor Branch 4, Division of ProjectManagement (DPM). This was the first and only
operating license issued through this Branch. 2
After the license was issued, responsibility for
TMI-2 was retained in DPM until August 1979. 3 Earlier attempts to transfer TMI-2 were rejected by theDivision of Operating Reactors (DOR). 4 This is attributable to the lack of resources in both divisions, 5
and reflected DOR's refusal to assume responsibility
for TMI-2 in view of the number of outstanding
areas identified as license conditions. 6

Amendment No. 2

This amendment removed license conditions that
had been completed, revised other conditions, andadded one condition. The following license conditions were satisfied and thus deleted, or were modifled to reflect agreements between the staff and theli censee:8'9

1. License paragraph 2.C.(3).b. The licensee hadprovided voltage and frequency variations resulti ng from a 500-kW load rejection from the diesel
generators.
2. License paragraph 2.C.(3).1.1. Design details of
an automatic water suppression system in eachdiesel generator room basement was submitted
to the NRC as required.
3. Paragraph 2.C.(3).1.2. The licensee provided afirewater pipe rupture analysis and indicated thatdesign of appropriate water spray protection
would require further analysis (see 4 below).
4. Paragraph 2.C.(3).1.3. This condition was revised
to assure that design of water spray protection
features would be accomplished at a suitable
later time and paragraph G.12. was added to theli cense to require installation of the automaticwater suppression system.

b. Amendments, Exemptions, andModifications to the TMI-2 License
Amendments, exemptions, and modifications to
the TMI-2 license as well as additional related staff
actions are summarized below.

With the exception of paragraph 2.C.(3).b, theabove conditions all related to fire protection. Implementation of fire protection measures was not
required until startup following the scheduled refueli ng outage in April 1980. This schedule appears tohave been arbitrarily selected; the staff's safety
analysis did not provide the basis for this or any
other implementation schedule.

Amendment No. 1

In the interest of minimizing delays, technicalspecification requirements were waived, and hydrostatic testing of the primary coolant system was
permitted at a lower system temperature prior to initial criticality. Hydrostatic testing of new pressure
boundaries was required to test the pressure boundaries which resulted from plugging of steam generator tube sheets, replacement of reactor coolant
pump gaskets, and installation of instrumentation in

Authorization to Proceed to Operational Mode 4Hot Shutdown

The licensee had completed paragraphs B.l andB.2 of Attachment 2 to license, which contained the30testing requirements to be completed prior to enteri ng mode 4. Accordingly, these paragraphs weredeleted.10

makeup tank isolation valves were installed pursuant to license paragraph F.1A

6. Paragraph F.2 of Attachment 2 was revised tocorrect a typographical error. This paragraph,
which was included as an original license condition, exempted the licensee from technicalspecifications for the hydrogen purge air cleanup
systems. Evidently, charcoal in certain filters
meet Regulatory Guide
could not be changed to 1.52, Revision 1, "Design, Testing, and Maintenance Criteria for Post Accident Engineering
Safety Feature Atmosphere Cleanup System Air
Filtration and Absorption Units of Light-WaterCooled Nuclear Power Plants." The exemption
permitted operation until the first refueling,scheduled for April 1, 1980.

Amendment No. 3

Amendment No. 3 reflected the fact that particular requirements had been satisfied and thus thatthe relevant license conditions were no longer required. These and the other revisions of thisAmendment are discussed below:,"
1. License paragraph 2.C.(3).c was deleted since
the licensee had provided documentation of its
proposal to permit utilization of smaller impellers
i n the reactor building emergency cooling booster
pumps.
2. License paragraph 2.C.(3).d was deleted to reflect the licensee's provision of documentation
demonstrating the adequacy of the net positive
suction head for the reactor building spraypumps.

Authorization to Proceed to Operational Mode 2Startup

A staff letter to Metropolitan Edison Company( Met Ed) authorized it to proceed to operationalmode 21 2 The licensee had completed the test requirements of paragraph C and G in Attachment 2
to the license required for startup. Completed items
i ncluded test procedures, environmental-admini strative procedures, various work list items, installation of makeup tank hydrogen isolation valves, andprocedure revision.

3. License paragraph 2.C.(3).e was deleted because
the licensee had provided analyses defining thecontainment temperature response to a steam
li ne break, and had justified the adequacy of environmental qualification temperatures of components inside containment.

4. Paragraph C.1 of Attachment 2 was revised todelete as requirements for entry into mode 2
three fuel handling system tests and to add a testof the reactor coolant waste evaporator. Technical specifications already required tests of thefuel handling equipment equivalent to those deleted here, and newly added paragraph 1 required acomparable test of the waste evaporator. Paragraph 1 was added to Attachment 2 to require
this waste evaporator test. The testing procedure for the reactor coolant waste evaporator
was delayed because part of the waste evaporafor was being used in TMI-1. During this time, theprocessing of radioactive waste for TMI-2 was
performed by TMI-1. Postponement of this test
permitted entry into mode 2 (startup) approximately 2 months ahead of schedule.

Three Pump Operation

Metropolitan Edison notified the NRC by letter ofMarch 29, 1978, of its intention to operate at powerusing only three of the four coolant pumps since the13
antirotational device had failed on the fourth pump.
Before the letter was sent, the reactor went criticalon three pumps at reduced power, as authorized by
the technical specifications.
The Commission
responded by requesting the licensee to analyze
certain transients to document
the safety margins
14
for longer term operation.
Evidently, the staff
determined, however, that short term operation was
acceptable on the basis of similar analysis for other
Babcock & Wilcox (B&W) plants because no
analysis of that issue was requested.
The licensee informed the Commission on May
12, 1978 that the fourth pump had been repaired,extended operation with three pumps was not anticipated, and the operating margins need not be
qualified. The Commission apparently agreed, because no NRC reply could be found in the docket
files.

5. Paragraph C.5 of Attachment 2 was revised toclarify the required equipment alignment to assure that the emergency core cooling high pressure injection pumps would not empty the makeup tank in the event of a loss-of-coolantaccident. This measure was compensatory andhad been required until redundant automatic

31

Authorization to Proceed to Operational Mode 1Power Operation

condition for operation (LCO) required that the control rod hoist be tested with the same loading capacity as the fuel assembly hoist. The safety analysis
concluded, however, that the control rod handlingmechanism could be tested for different loadings
than required for the fuel assembly handlingmechanism, and Amendment No. 5 reflected that
determination. 18

By letter of April 7,1978, the Commission authorized Metropolitan Edison to proceed to power
operation, because all of the items in Attachment 2
required to initiate this mode had been completed.15
Those items were as follows:

1. Optimization of voltage levels at the safetyreiated bases and verification of such optimization (paragraph D.1).
2. Modification of the diesel generator air starting
system to provide 10 starts (paragraph D.2).
3. Making the intermediate closed cooling water
heat exchangers seismic Category I.

Deletion of Pseudo Rod Ejection Test

I n response to Metropolitan Edison's request to
delete this test from the TMI-2 startup and test program because of unnecessary radwaste and consumption of 24 hours of time that could be used
more productively, 19 the NRC eliminated this requirement. 20 The staff approved Metropolitan
Edison's technical justification based on similar tests
at the Davis Besse and Rancho Seco plants and verification of the prediction models based on these
data. The same models were used in the safety
analysis of TMI-2.

Relief from Testing Requirements

In response to Metropolitan Edison's request for
relief from certain requirements of the inspection
and testing requirements, as specified in Section XIof the ASME Boiler and Pressure Vessel Code and
Addenda, the Commission granted relief pursuant to
10 C.F.R. Sec. 50.55a because "compliance would
result in hardships and unusual difficulties without acompensating increase in the level of safety." Thestaff's safety analysis indicated that such relief wasappropriate pursuant to 10 C.F.R. 50.55a(6)(i), andthe relief granted encompassed the period fromli cense issuance until the initiation of commercial
16
operation (February 8 to December 30,1978).

Amendment No. 6

The license
was amended to permit a number of21changes:

1. Alternate procedures for containment air lockleak rate testing.
2. Plant operation with an increase in ultimate heatsink temperatures from 88° to 98°F. The upperli mit temperature was limited to 90°F, however,until the impellers in the control building booster
pumps were changed to produce more flow and,i nturn, provide adequate cooling to the control
building air conditioning equipment.
3. Removal of most of the orifice rod assemblies
and the installation of retainers on the remaining
assemblies and on the burnable poison rod assemblies. The core flow technical specifications
had to increase to compensate for increased
bypass flow due to removal of the assemblies
and the addition of the retainers. As a result of
these changes, the operating margin in flow rate
between measured and technical specification
requirements was reduced from 5 to 3%. The
accuracy of the flow instrumentation is important
to ensure this margin. The flow measurement
system and its calibration was approved by the
NRC based on the measurement uncertainty forthe same system in TMI-1 of 1.5%, which resulted
i n a net operating margin of 1.5%. On the basis of
this small margin, the staff probably should haverequired measurement of the uncertainty in TMI2, but they did not.

Amendment No. 4

As a result of two emergency core cooling system injection occurrences where sodium hydroxide
was inadvertently and unnecessarily injected into
the reactor coolant system, the licensee requested
and received approval to change the actuation signals to the controlling value for the sodium hydroxi de tank. In addition, Amendment No. 4 responded
to a B&W finding that the incore nuclear detectors
for indicating quadrant tilt and axial imbalance possessed more uncertainty than initially assumed.
Although the staff had not fully completed its review
of B&W analysis, they approved the proposedchanges to the alarm setpoints for quadrant tilt limits. 17
Amendment No. 5

Technical specifications were changed to reflect
testing of the control rod handling mechanism forl oads within its design specifications. The originaltechnical specifications for determining the limiting32

4. Replacement of the 12 steam safety valves
resulted from the failure of these valves to reseat
during a previous transient. Twenty smaller safety valves were installed, which provided 6% more
flow than the original valves.
5. An increase in the reactor coolant system low
pressure trip setpoint from 1800 to 1900 psig.
The reactor coolant system low pressure trip
setting was changed primarily to increase operating flexibility and to reduce unnecessary highpressure injection actuation of the emergency
core cooling system.
6. Miscellaneous revisions of the technical specifications to reflect correctly the rod bow penalty
and the addition of allowable valves of instrumentation inaccuracies into the channel function test
acceptability requirements.

the Commission adopted B&W's and Metropolitan
Edison's proposed solution by issuing an order for
modification of license on May 26, 1978, whichamended the TMI-2 operating license to restrict
power to 2568 MW. The other B&W plants whose
operating licenses were similarly modified were
Oconee 1, 2, and 3, TMI-1, Arkansas Nuclear 1, Crystal River 3, and Rancho Seco.
When it notified the Commission of the problem
recognized by B&W, Metropolitan Edison indicatedthat authorization to operate at a power level of
2568 MW was sufficient to respond to this matter,and that no further corrective action should be required. The Commission's modifications of theTMI-2 operating license adopting this approach isquestionable for reasons discussed below.
As part of its justification to operate at this reduced power level, Metropolitan Edison indicatedthat the control room operator was trained torecognize the symptoms and drilled to respond to asmall break LOCA. Instruments indicating the pressurizer level and pressure-both nonsafety-related
equipment-were identified by the licensee as thecontrol room instrumentation to be used by theoperator to ascertain the small break LOCA symptoms and thus to initiate corrective action. Theli censee further indicated that no operator actions
would be required if the power level was further reduced to less than 63% of full power, or 1764 MW.
The Commission's acceptance of Metropolitan
Edison's justification for operation at 2568 MW was
i nconsistent with the general staff position that nosafety credit was to be given for operator actions
that are required within 10 minutes of the accident
and that nonsafety grade equipment cannot be reli ed on to mitigate an accident. The solution advanced by the licensee and accepted by the Commission in part assumed that, within 2 minutes of
the accident, the operator would analyze his instrumentation and determine whether there was a lossof offsite power concurrent with a diesel or makeup
pump failure and a small break LOCA. In the eventthe operator recognized such an occurrence, it was
further assumed that an auxiliary operator would bedirected to the auxiliary reactor building to open
cross current valve between high pressure injection
trains and, while in communication with the control
room operator, manually open the two other valves
to obtain a certain flow rate through each valve.
During this time, the control room operator would be
required to verify that the normal makeup valve wasclosed. If all this occurred, the required flows would
be established within 10 minutes after the actuation
signal for the emergency core cooling system.
Subsequent experience with operator reactions

Amendment No. 7

This amendment deleted environmental license
conditions that had been completed by the licensee.
The deletions included a creel survey and aerial remote sensing requirement. Amendment No. 7 also
reflected an administrative change in the Appendix
B technical specification.22
Amendment No. 8

This change in the technical specification permitted operation at reduced power levels with reduced
reactor coolant system flow. Previously, the technical specification required design flow rate regardl ess of the reactor power level.23
Amendment No. 9This amendment incorporated the modified
Metropolitan Edison's amended physical security
plan into the license. 24
Orders for Modification of License

Orders for modification of license were issued on
May 26, 197825 and October 13, 1978. 26 I n accordance with 10 C.F.R. Part 21, on April 12, 1978, B&W
reported a safety concern regarding small breakl oss-of-coolant-accident (LOCA) analyses to the
NRC. A small break LOCA at the pump discharge
with an accompanying single failure was calculated
by B&W to be more limiting than the small breakidentified previously as the worst-case small break
LOCA pursuant to the ECCS Evaluation Models set
forth in Appendix K to 10 C.F.R. Part 50. After analyses and submissions by B&W and the licensee,
33during the next refueling stage. The justification
cited by the NRC for the extension included:

at TMI-2 demonstrate that these assumptions werefaulty. In addition, the NRC staffs safety analysis
i ndicated that there was some uncertainty concerni ng other assumptions employed in the B&W anal yses. The safety evaluation stated:

The public interest is served by issuing this exemption for TMI-1 in that in the absence of an exemplion, shutdown of the facility would be required.
Loss of the large block of generating capacity
could adversely affect electric system reliability andthus possibly adversely affect the public.

[ We] [NRC staff] cannot conclude at this time that
operation of TMI-2 at 2568 megawatts thermal
would be fully in conformance with 10 CFR Part
50.46. On the other hand, the range of calculations
now available shows that for operation of this facility at power levels up to 2568 megawatts thermal,
ECCS performance calculations for the limiting
small break indicate that this break has a very substantial margin on peak clad temperature below thelimits of 10 CFR Part 50.46(b) if appropriate operafor action is property taken (as described above). -'O

c. Pending Regulatory Actions
The following technical specification change requests (TSCR) were submitted by the licensee for
NRC review and approval as of March 29,1979:

On October 13, 1978, the NRC issued the second
order for modification which superseded its order of
May 26, 1978. This second order specified that thepower level could be increased to the maximum authorized reactor power level of 2772 MW. As partof the effort to justify operation at the maximum
power level, changes to a previously NRC approved
ECCS evaluation model were requested by B&W
and subsequently accepted by the NRC; this extended the time within which operator action was initially required. Although the order stated that "continued reliance on operator action to perform the required steps to ensure plant safety on a permanent
basis is undesirable ... ", the staff had not reviewed
the licensee's proposal of schedule for a permanent
solution, and it did not form the basis for any
evaluation supporting the order. Although thissecond order directed the licensee to undertake
ECCS modifications to eliminate future reliance on
prompt operator actions in accordance with an approved schedule, it reiterated the Commission's approval of the same operator actions for mitigating
the small break LOCA approved in the first order.
The permanent modifications that would eliminate
prompt operator action were approved for TMI-2 on
December 8, 1978. 27 These permanent modifications were scheduled to be completed during thefirst refueling outage scheduled for April 1980.
The same issue was considered for TMI-1. By
letter of November 21, 1978, 28 the licensee requested that the NRC grant an extension of the exemption to 10 C.F.R. Part 50.46 for TMI-1 until early
1980. This extension would be one year after thescheduled refueling outage in February 1979. Duri ng this one year extension, the licensee proposed
to continue to rely on operator actions as
described. On March 16, 1979, NRC approved thisrequest based on, among other considerations, thefinancial penalty imposed on the licensee if themodifications were performed at an earlier date than

TSCR #003-re: The adequacy of patrolling fire
watches vs. continuous watches.
, TSCR #006-re: Miscellaneous changes to theadministration section of TMI-2 technical specifications.
, TSCR #016-re: Defeating fast transfer of station balance of plant loads upon the failure of an
auxiliary transformer.
, TSCR #17-re: Operability of control rod reedswitch position indicator channels.
, TSCR #10-re: Frequency for performing heatbalances.
o

In addition, Commission had received requested
submissions regarding the licensee's proposedcourse of action in several areas, including the following:
1. Reactor Building Purge Valve Analysis - NRC
Request, 11/29/78; Met Ed Response, 3/16/79
2. Single Auxiliary Transformer-Operation NRC
Request, 8/18/78 (verbal); Met Ed Response,
8/29/78
3. Inservice Instrumentation- Met Ed Submission,
7/25/79
d. Status of Pertinent Commitments to theRegulatory Staff
The following lists the status of Metropolitan
Edison's commitments to provide information to theCommission and to32take other specified actions asof March 29,1979.
Environmental Qualification of Electrical
Components-IE Bulletin 79-01

Review was completed by the licensee before
March 27, 1979. The response was being preparedfor submission to the NRC.
34

Small Break LOCA Piping Crossconnect

the remaining items within the time periods initiallyset forth in the operating license. A discussion of
the items that had not yet been completed follows.
The operating license required Metropolitan Edison to take the following actions before startup following the first regularly scheduled refueling:

Work was progressing toward installation of thisequipment at the first scheduled refueling outage in
April 1980.
Feedwater Isolation Valves

1. Provide a second level of voltage protection forthe onsite power system.
2. Modify the system design to automatically
prevent load shedding of the emergency buses
once the onsite sources are supplying power toall sequence loads on the emergency buses.
This load shedding feature was required to havethe capability of being automatically reinstated if
the onsite source supply breakers are tripped.
3. Provide recommended technical specifications foritems (1) and (2) specified above, including test
requirements to demonstrate the full functional
operability and independence of the onsite powersources.
4. Install an environmental temperature monitoring
system to ensure that the environment at the location of Class IE equipment in buildings outsidecontainment is maintained within the temperature
range for which the equipment is designed tooperate.
5. Submit appropriate descriptions and analyses
and modify the secondary (main steam and feedwater) systems so that the consequences of aspontaneous break anywhere in a secondary
system line will be mitigated only by safety grade
equipment, with nonsafety grade equipment pera
mitted to
backup for the equipment. For assumed sin-as gradegle failure of serve
safetyportions of the secondary systems where abreak might be caused by a seismic event,Metropolitan Edison Company was required tomodify the systems so that accident consequences will be mitigated only by seismic
Category I components after assuming single
failure in any seismic Category I component.
6. Submit and implement a response time testing
program for the protection system.
7. Modify the reactor coolant pressure boundary
overpressure protection system to satisfy Commission requirements regarding credit for operafor action, single failure criteria, testability, seismic design, and IEEE-279 criteria, and effect on reliability of other safety systems.
8. Complete modifications necessary to achieve thecapability to shut down the plant safely and independently of cabling and equipment in the cable spreading room, and add either a manuallyoperated fixed water system in the cable spread-Work was progressing toward installation ofsafety grade equipment at the first refueling outage.
Specifically, analyses were being performed todemonstrate design adequacy. The NRC had performed a preliminary design review and had approved the design concept, but had requested thedesign adequacy analyses before issuing a formal
design acceptance. Modification of the main steam
and feedwater systems is required by paragraph 3(i)of the operating license.
Asymmetric LOCA Loads

Work was progressing toward completion of theanalysis in June of 1980. B&W analyses of cavity
loadings and vessel/vessel internals loading was inprogress.
IE Bulletins

Work was underway to investigate the applicabil"Pipe of the concerns raised in IE Bulletin 79-02Pipe Support Base Plates" (issued March 8,1979)-and Bulletin 79-03-"Longitudinal Pipe
Welds" (issued March 13, 1979)-which were submitted to TMI-1 and TH-2. The architectengineering firm for each unit had been instructed toi nvestigate the extent to which IE Bulletin 79-02 applied. This investigation was underway but had notbeen completed. The licensee had determined thatI E Bulletin 79-03 was not applicable to TMI-2, but
the investigation for applicability for TMI-1 had notbeen completed.
Security

The TMI security plan had been approved, andwork was underway to implement some security
systems. However, compensatory actions approved by the NRC were in effect.
License Conditions

The TMI-2 operating license stipulated that certain items should be completed within a specified
ti me frame. Several items had been completed before March 27, 1979, and work was continuing on
35

i ng room, or fire retardant insulation around eachcable tray in the cable spreading room not readily
accessible to a manual fire hose stream so thatno fire would be expected to affect redundantsafety trains.
9. For all fire doors, provide electrical fire door supervision with time delayed alarms in a constantly
manned area, lock the doors closed, or provide
acceptable hold-open features for identified
doors designed to close in the event of a fire.

Pending such charcoal replacement, Metropolitan
Edison Company has been exempted from compliance with the above technical specifications.
3. Provide an automatic water suppression systemi n each diesel generator room basement.
e. Findings
1. The TMI-2 license contained a number ofsafety-related conditions that were not requiredby the staff to be completed before the issuanceof the operating license. Apparently no NRC criteria exist for the number or kind of outstanding
issues that are permitted when a license is issued.
2 The NRC approved operator action to mitigate asmall break loss-of-coolant-accident for B&W
plants was questionable. The time (2 minutes)
available to the operator to identify the accident
i s insufficient, and the information to which theoperator was expected to respond is provided bynonsafety-related instrumentation.
3. The transfer of TMI-2 and other plants from theDivision of Project Management to the Division of
Operating Reactors is not timely. Consequently,
responsibility for part of the most important
operating history-preoperational and startup
testing-is not vested in the appropriate NRC
Division of Operating Reactors.

Attachment 2 to license required that the followi ng activities be completed before startup after the
first regularly scheduled refueling outage:
1. Provide redundant automatic safety grade makeup tank isolation valves (MU-V-12) actuated by and engineered safety features signal.
2. Replace the charcoal in the filters in the following
systems so that the requirements of the indicatedAppendix A technical specifications will be met.

SystemTechnical Specification

Hydrogen Purge Air Cleanup

4.6.4.3.b.2, 4.6.4.3.cControl Room Emergency Air
Cleanup
Fuel Handling Building Air
Cleanup

4.7.7.1.c.2, 4.7.7.1.d
4.9.12.b.2, 4.9.12.c

36

REFERENCES AND NOTESLetter from S. Varga, NRC, to J. Herbein, Met Ed,
Subject: Three Mile Island Nuclear Station, Unit 2I ssuance of Amendment to Facility Operating License,
dated May 19,1978.
Letter from S. Varga, NRC, to J. Herbein, Met Ed,
Subject: Three Mile Island Nuclear Station, Unit 2I ssuance of Amendment to Facility Operating License,
dated June 5,1978.
19
Letter from J. Herbein, Met Ed, to Director of Nuclear
Reactor Regulation, NRC, Subject: Psuedo Ejected Rod
Test Delection, dated May 19,1978.
20
Letter from S. Varga, NRC, to J. Herbein, Met Ed,
Subject: Deletion of Psuedo Rod Ejection Test at TMI-2,
dated June 12, 1978.
21
Letter from S. Varga, NRC, to J. Herbein, Met Ed,
Subject: Three Mile Island Nuclear Station, Unit 2Issuance of Amendment to Facility Operating License,
dated August 17,1978.
22
Letter from J. Davis, NRC, to J. Herbein, Met Ed,
Subject: Three Mile Island Nuclear Station, Unit 2Issuance of Amendment to Facility Operating License,
dated September 5,1978.
23 Letter from S. Varga, NRC, to J. Herbein, Met Ed,
Subject: Three Mile Island Nuclear Station, Unit 2Issuance of Amendment to Facility Operating License,
dated December 15, 1978.
24
Letter from S. Varga, NRC, to J. Herbein, Met Ed,
Subject: Three Mile Island Nuclear Station, Unit 2Issuance of Amendment to Facility Operating License,
dated February 23, 1979.
25
Letter from S. Varga, NRC, to J. Herbein, Met Ed,
Subject: Transmitting Order for Modification of License,
dated May 26,1978.
26
Letter from S. Varga, NRC, to J. Herbein, Met Ed,
Subject: Transmitting Order for Modifications of License,
dated October 13, 1978.
27
Letter from R. Reid, NRC, to J. Herbein, Met Ed,
Subject: Facility Modifications to Eliminate Reliance on
Operator Action Following a Small Break LOCA, dated
December 8,1978.
28
Letter from J. Herbein, Met Ed, to R. Reid, NRC,
Subject: Small Break LOCA Long Term Modification,
dated November 21, 1978.
29 Letter from R. Reid, NRC, to J. Herbein, Met Ed,
Subject: Three Mile Island Nuclear Station, Unit (Issuance of Amendment to Facility Operating License,
dated March 16,1979.
30
NRC, "Modifications of Conditions of Exemptions,"
Federal Register, Vol. 44, No. 63, March 30,1979.

'Three Mile Island Nuclear Station Unit 2, Facility
Operating License, License No. DPR-73, February 8,
1978.
2
Varga dep. at 19.
3
Memorandum from D. Vassallo, NRC, to D. Eisenhut,"Transfer of THREE MILE ISLAND NUCLEAR STATION,
UNIT 2 (TMI-2) to Operating Reactors," August 22,1979.
4
Varga dep. at 31.
5
Vassallo dep. at 38; Varga dep. at 31.
6
Memorandum from V. Stello, NRC, to D. Vassallo,"Transfer of TMI-2 to DOR," September 26, 1978. The
same responses existed for delayed transfer of Davis
Besse, Unit I from Division of Project Management to Division of Operating Reactors for 18 months. Vassallo dep. at 35.

17

Letter from S. Varga, NRC, to J. Herbein, Met Ed,
Subject: Three Mile Island Nuclear Station, Unit 2I ssuance of Amendment to Facility Operating License,
dated March 3, 1978.
8
Letter from S. Varga, NRC, to J. Herbein, Met Ed,
Subject: Three Mile Island Nuclear Station, Unit 2I ssuance of Amendment to Facility Operating License,
dated March 10, 1978.
sMemorandum from H. Denton, NRC, to Commissioner
Ahearne, "Evolution of TMI-2 Operating License," July 2,
1979.
10Letter from R. Boyd, NRC, to J. Herbein, Met Ed,
Subject: Three Wile Island Nuclear Station, Unit 2Authorization to Proceed to Operational Mode 4, dated
March 10, 1978.
11
Letter from R. Boyd, NRC, to J. Herbein, Met Ed,
Subject: Three Mile Island Nuclear Station, Unit 2I ssuance of Amendment to Facility Operating License,
dated March 24, 1978.
12

Letter from R. Boyd, NRC, to J. Herbein, Met Ed,
Subject: Three Mile Island Nuclear Station, Unit 2Authorization to Proceed to Operational Mode 2, dated
March 25, 1978.
13

Letter from J. Herbein, Met Ed, to S. Varga, NRR,
Subject: Power Operation with Three Reactor Coolant
Pumps, dated March 29,1978.
14

Letter from S. Varga, NRC, to J. Herbein, Met Ed,
Subject: TMI-2 Partial Loop Operation, dated May 3,
1978.
15

Letter from R. Boyd, NRC, to J. Herbein, Met Ed,
Subject: Three Mile Island Nuclear Station, Unit 2Authorization to Proceed to Operational Mode 1, dated
April 7,1978.

31

Letter from J. Herbein, Met Ed, to M. Rogovin,
NRC/SIG, Subject: Ref. NTFT M790626-01, at 7, dated
July 9,1979.
32
1d. at 10.

'*Letter from S. Varga, NRC, to J. Herbein, Met Ed,
Subject: Respond Inservice Testing Program for Pumps
and Valves for Three Mile Island Nuclear Station Unit 2(TMI-2), dated April 21,1978.

37

3. OTHER RELEVANT MATTERS

staff, and the other was the head of the standards
organization. The chairman and all of the members
were appointed by the director of regulation. The
members' participation reflected their personalviews as opposed to those of their respective organizations.4 I n 1975, when the Nuclear Regulatory
Commission was formed to replace the Atomic Energy Commission, the RRRC began to report to the
Executive Director for Operations (EDO), and its
membership increased to reflect the significant
managerial and functional changes. The Offices ofStandards Development and Regulatory Research
had single representatives, and the Office of Inspeclion and Enforcement had two representatives.
However, with the chairman and four otherrepresentatives, the Office of Nuclear Reactor Regulation (NRR) retained a majority of the voting
members. The RRRC organization also included a
SeCretary to organize and record the minutes of themeetings and a technical representative from the office of the Executive Director, both of whom werenonvoting members. 5 The voting members of the
RRRC had senior management responsibilities in the
NRC, and their participation in the committee was ofnecessity limited to attendance and some preparation for the meetings. No permanent staff was assigned to the RRRC to assist in assessing thematters under consideration or in monitoring the implementation of its recommendations when ap6
proved by the director of NRR.
The recommendations of the RRRC are determined by the majority vote, based largely on informed engineering judgments of its members. 7,8
The material submitted to the RRRC for its review
includes a technical description for the proposedchange, a discussion of the need for the change,
and the value-impact assessment which includes arecommended process for implementing the change,
if approved. The value-impact assessment of new
or revised requirements is prepared by the branchor groups originating the change in requirements
proposed by the committee. This assessment addresses the value and impact of the requirement on
the NRC, the industry, and the public from both an
economic and a safety perspective.
The value-impact assessment provides a sourceof information in the decision process. 9 However,
because of the generally poor quality of these assessments, their contribution is minimal. Determinations of the RRRC still largely reflect the individual
j udgment of the members, informed by general
opinions, background, and knowledge they obtainfrom other sources. Industry has criticized thesevalue-impact statements,11 and the committee itself
has frequently referred an issue back to the staff

a. Regulatory Requirements Review
Committee
Background

The Regulatory Requirements Review Committee( RRRC) was established in March 1974 by the
Atomic Energy Commission's director of regulations
to review new regulatory requirements and changes
to current requirements and to determine whether,when, and where these changes in requirements
should be applied. 2 This and other aspects of theCommission's regulatory program were prompted inpart by industry charges that changes in regulatory
requirements that were not needed for safety werebeing imposed by the regulatory staff without
management review or control.
The industry
charged that this process, which was generally referred to as "ratcheting," imposed new requirements
on previously approved designs and previously established licensing criteria. Industry officials also
charged that the "ratcheting" process substantiallycontributed to the long delays in the granting ofsome construction permits and operating licenses.
Thus the review committee was established to contribute to a more systematic approach to determini ng when to impose new requirements on plants at
various stages in the licensing process.
I n addition, other aspects of the regulatory program for controlling ratcheting included staff reorganization along technical disciplinary lines, publication of a regulatory guide for the format and content
of safety analysis reports, revisions to regulatory
guides for promulgating new staff positions, and thedevelopment of Standard Review Plans 3 defining all
safety requirements which must be satisfied during
the review process. The regulatory program objective was never intended to eliminate ratcheting. Instead, it was designed to stabilize the licensing process and to assure that any ratcheting that did occur was done with the knowledge and approval ofsenior management within the Commission staff.
The overall objective was that the implementation of
the NRC's standardization policy in conjunction
with the discipline imposed by the RRRC would stabilize the designs provided by industry and the regulatory requirements established by the Commission.
The charter membership of the committee consisted of five senior management representatives of
the NRC. The chairman and two of the othermembers were from the licensing staff, one member
was the head of the inspection and enforcement38because of their inadequacies. Finally, although thevalue-impact statement contains a recommendation
for implementing the issue, the RRRC does not haveits own guidance or criteria available to its members
to cast their votes in categorizing the issue. 8
I n reaching a decision to backfit requirements toexisting plants, the RRRC relies on the criteria 4 i n 10
C.F.R. 50.109, Backfitting. As a practical matter,
however, this section of the regulations does notprovide sufficient guidance for backfitting deck
sions.12 " Other than the hortatory feelings it
creates, it's meaningless." 8 The committee does
not document the guidance or criteria its members
use in casting their votes. Moreover, although asummary of the meeting and the RRRC decisions
was transmitted in a memorandum to the EDO, thechairman of the committee testified that he was
uncertain of any action taken as a result.13

An issue is usually placed in category II when it
cannot be clearly categorized as a category I or III.
For example, if sufficient information is not available
or if the benefits and requirements for certain partsof a regulatory guide cannot be ascertained, the issue is placed in category II. While this practice
prevents delay in publishing the guide, 15 it alsol eaves its implementation to individual staff interpretations, thus creating the potential for ad hoc
ratcheting and allowing the very kind of uncontrolledescalating regulatory requirements that the committee was created to minimize. In addition, matters involving categories 11 and III caused confusion amongstaff members when the manner and schedules fortheir implementation were taken into consideration.
As a result, some category 11 items have not beeni mplemented by the staff. 16

Although category III mandates the backfitting ofa particular requirement, there appears to be no
direct relationship between a category III determination and the regulatory backfit requirement in 10
C.F.R. 50.109 that this "additional protection ... isrequired for the public health and safety." The absence of criteria allows considerable RRRC flexibility
i n judging the improvement in safety for a category
III issue. 17 Furthermore, the NRR has established its
own category IV classification for regulatory requirements that are considered by both an NRR division
director and the office director to be of sufficient
potential safety importance to warrant regulation of
applicants
and licensees before review by the
18,19
RRRC.
These category IV requirements are to
be submitted for RRRC review as promptly as practical. Obviously, this dilutes the RRRC's overall control at the ratcheting process. Because applicants
theoretically cannot be required to comply with thecategory IV requirement if it is later deemed to be oflesser significance by the eventual RRRC decision,
they generally try to avoid a timely response to acategory IV requirement, hoping for an outcome
more favorable to their position.

Discussion of Operation

The RRRC considers matters having a potential
for substantial impact on virtually all phases of thelicensing process of nuclear plants.
The
committee's recommendations reflect its view of
how the issues, if approved by the director of NRR,
should be implemented by the staff. Its implementation categories were defined for regulatory guides in1975 in meeting number 31, 14 which subsequently
was adopted for all issues considered by the RRRC.
The committee's options are to reject or defer
the proposed changes altogether or to determine ani mplementation schedule for them. RRRC decisions
to implement particular requirements rather than toreject or defer them are classified in the following
categories:
Category I-Clearly forward fit only by implementi ng the change only on current and future applications. No further. staff consideration of possible
backfitting is required.

Category II-Further staff consideration of the needfor backfitting appears necessary for certain identified items of the regulatory position. A category 11
determination reflects the judgment that existing
plants should be evaluated to determine their status
with regard to these safety issues and to determine
the need for backfitting on existing plants, designs
and sites on a "case-by-case" basis.

The independence of NRR in deciding to implement the committee's category requirements further
dilutes the committee's authority. In some cases,
the director of NRR has chosen not to implement
20
some RRRC decisions.
I n other cases, staff limitations have prevented implementation of other
RRRC decisions21which have been approved by the
director of NRR.

Category III-Clearly backfit to apply the proposedchange to existing plants, designs and sites. Existi ng plants should be evaluated to determine whether
i dentified items of the regulatory position are
resolved in accordance with the guide or by someequivalent alternative.

Although the committee initially was establishedto maintain a stable baseline of regulatory requirements, it has evolved as the focal point for controlli ng racheting
requirements during the licensing pro22
cess.

39

1978 by the Division of Project Management (DPM),
which developed a program to ensure that category
II and III requirements were implemented for plants,
applications, and designs within their scope of
responsibility. The Division of Operating Reactors( DOR) likewise assured implementation of these requirements for all other operating plants and for27
plants scheduled for operation in 1978.
Previousl y, only category I issues had been implemented by
the staff as additional regulatory requirements.
General implementation problems remain, however, as is illustrated by the fate of Regulatory Guide
1.97, "Instrumentation for Light-Water Cooled Nuclear Power Plants to Assess Plant Conditions Duri ng and Following an Accident." This revision toplant safety standards, which in light of the accident
at Three Mile Island should be applied to existing
plants, was deleted from the list of category II issues
to be reviewed by the Systematic Evaluation Program branch of the DOR. According to a memorandum circulated among branch members 9 days after
the accident at TMI-2, the change was not made to
the NRC requirements due to a lack of implementation guidance. 28 Moreover, revisions to the safety
requirements of only 11 plants (none of which is B&W
design) are presently under review by the Systematic Evaluation Program.

The committee's categorization of regulatory
guides applies to the regulatory position section of
the guide but is not published in the implementation
section of the guide. The regulatory position section contains the NRC requirements and the implementation section indicates how the guide is supposed to be applied in the licensing process. However, the RRRC had decided in 1975 that the implementation section should address only therelevance of the guide to new applications. Consequently, the applicants and licensees were not apprised of the actual implementation to be effectedby the staff for reviewing ongoing applications or for
licensed facilities or approved designs. Representatives of the utilities and vendors complained that thestaff's actions in imposing the regulatory positions
did not reflect what was specified in the implementation section. 23
I n response to industry concerns that they were
not afforded notice of, or opportunity to comment,or participate in the RRRC's decisions, thecommittee's operating procedures were changed toprovide an opportunity for public input. Beginning inearly 1979, the subject matters to be considered by
the RRRC are published in the Federal Register andthe supporting information (e.g., value-impact statements) is made available to the public. A period ofti me, usually 60 days, is provided for public comment. After the comment period, the RRRC considers the matter. The positions recommended by the
RRRC and approved by the director of NRR arethen published and an opportunity is afforded forappeal.24 Approved RRRC recommendations are
not usually effective until 30 days after they are
published.
Neither the NRC nor the RRRC has established
any procedures for ensuring that approved committee recommendations are implemented. 25 Generally, the NRC office involved in the decision has the
responsibility for its implementation. For example, achange to a regulation is the responsibility of thedirector of the Office of Standards Development; achange in licensing criteria is the responsibility ofthe director of NRR. Because the division directors
are committee members and a summary of thecommittee's meetings is distributed to the assistantdirectors of the divisions and to other NRC
managers, the Commission may assume that implementation will be initiated and completed by indivi26
In
duals responsible for particular requirements.
practice, however, the implementation of approved
RRRC recommendations is far from uniform.
The first systematic program to implement approved RRRC recommendations was initiated in

RRRC Actions

Because the RRRC began categorizing regulatory
requirements in 1975, 22 have been classified as
category II (Table 1-2) and 8 as category III (Table I3). The remaining regulatory guides and revisions
and branch technical positions, some 200 in
number, were classified as category I items.
A number of issues that were either classified asa category I item or were not reviewed and approved by the RRRC may warrant reconsideration inview of the accident at TMI-2. Illustrative examplesof these issues are contained in Table 1-4.
Findings
1.

40

The function of the Regulatory Requirements
Review Committee is an important part of NRC's
program to control the development of new regulatory requirements. Because of the need tochange regulatory requirements as the technology of risk assessment and of nuclear power
plant design develops, the function assigned to
the RRRC is important and must be
strengthened.

TABLE 1-2. List of category II recommendations
No.
1

2

3
4
5
6
7
8
9
10
11
12
13
14

15
16

I tem

FIG 1.27, Revision 2(1/76)FIG 1.52, Revision 1( 7/76)
NOTE: Revision 2,
Category I (7/77)

Design, Testing, and Maintenance Criteria for Engineered
Safety-Feature Atmosphere Cleanup System Air Filtration
and Adsorption Units of Light-Water-Cooled Nuclear Powerplants

Design Basis Floods for Nuclear Powerplants

RG 1.68, Revision 1(1/77)

I nitial Test Programs for Water-Cooled Reactor Powerplants

RG 1.63, Revision 2(11/77)

Electric Penetration Assemblies in Containment Structures
for Light-Water-Cooled Nuclear Powerplants

RG 1.91, Revision 1( Draft) 12/77)

Evaluation of Explosions Postulated to Occur on Transportation Routes Near Nuclear Powerplants

RG 1.97, Revision 1( 8/77)

I nstrumentation for Light-Water-Cooled Nuclear Powerplants
to Assess Plant Conditions During and Following an Accident

FIG 1.102, Revision 1(10/76)

Flood Protection for Nuclear Powerplants

RG 1.100 (3/76)

RG 1.105, Revision 1(11/76)

Seismic Qualification ofPowerplants

Electric

Equipment for Nuclear

I nstrument Setpoints

RG 1.108, Revision 1( 8/77)

Periodic Testing of Diesel Generators Used as Onsite Electric Power Systems at Nuclear Powerplants

RG 1.117, Revision 1(10/77)Tornado Design Classification

FIG 1.124, Revision 1(1/13/78)

Service Limits and Loading Combinations for Class 1 Linear
Type Component Supports

RG 1.115, Revision 1( 7/77)

Protection Against Low-Trajectory Turbine Missiles

RG 1.118 (6/76)

Periodic Testing of Electric Power and Protection Systems

RG 1.130 (7/77)

Design Limits and Loading Combinations for Class 1 Plateand-Shell-Type Component Supports

RG 1.137 (1/18/78)

19

BTP APCSB
9.5.1 (8/76)

20

Ultimate Heat Sink for Nuclear Powerplants

RG 1.59, Revision 2( 8/77)17
18

Subject

RG 8.8, Revision 2( 3/77)

BTP MTEB
5-7 (7/77)

Fuel Oil Systems for Standby Diesel Generators

I nformation Relevant to Ensuring that Occupational Radiation
Exposures at Nuclear Power Stations Will Be As Low As Is
Reasonably Achievable

Guidelines for Fire Protection for Nuclear Powerplants Under
Review and Construction
BWR Coolant Pressure Boundary Piping

41

TABLE 1-2. List of category II recommendations-Continued
No.
Item
21
22

RG 1.141( Draft) (4/78)

SRP 5.4.7
Revision (1/78)

Containment Isolation Provisions for Fluid Systems
Residual Heat Removal System

TABLE 1-3. List of category III recommendations
No.
1

2
3
4
5
6
7

8

I tem

Subject

Subject

RG 1.39
Revision 1

Housekeeping
Powerplants

RG 1.68.2 (1/77)

I nitial Startup Test Program to Demonstrate Remote Shutdown Capability for Water-Cooled Nuclear Powerplants

RG 1.56, Revision
1 (1/78)

RG 1.99, Revision
1, (4/77)
RG 1.101,
Revision 1 (3/77)

Requirements for

Water-Cooled

Nuclear

Maintenance of Water Purity in Boiling Water Reactors

Effects of Residual Elements on Predicted Radiation Damaget o Reactor Vessel Materials
Emergency Planning for Nuclear Powerplants

RG 1.114
Revision 1 (11/76)

Guidance on Being Operator at the Controls of a Nuclear
Powerplant

RG 1.127
Revision 1

I nspection of Water-Control
Nuclear Powerplants

RG 1.121 (8/76)

Bases for Plugging Degraded PWR Steam Generator Tubes
Structures

Associatedwith

TABLE 1-4. Illustrative examples relevant to the TMI-2 accident
1.

Regulatory Guide 1.97, Revision 1 - Instrumentation for Light Water Cooled Nuclear Powerplant Conditions During and Following an Accident.
This was categorized as Category II for operating plants.

2.

3.

4.

Revisions to Reactor Systems Branch Technical Position - "Reactor Coolant Systems Overpressuri zation Protection."

RRRC recommended giving credit for operator action and did not require mitigating equipment to be"safety related." It was not required to be backfitted to operating plants.
Regulatory Guide 1.7, Revision 2 - Control of Combustible Gas Concentrations in Containment Following a Loss-of-Coolant Accident.

This guide and associated change to 10 CFR 50 was categorized as Type 1 - no backfit. Provisions would require measurement, mixing, and dilution of atmosphere.

Regulatory Guide 1.141 (for comment) - Containment Isolation Provisions for Fluid Systems.

Categorized as a Type II. It would include requirements for diverse actuation signals for containment isolation, leak testing, and valve position indication in control rooms.
42

TABLE 1-4. Illustrative examples relevant to the TMI-2 accident-Continued
5.

Revision to Branch Technical Position, RSB-5-1 - "Design Requirements of the Residual Heat
Removal System."Categorized as Type II. It would eliminate susceptibility of operating reactors to single failures in the
Residual Heat Removal System.
6.

7

Regulatory Guide 1.101, Revision 2 - Emergency Planning for Nuclear Power Plants.

Revision 2 was not considered by RRRC (insignificant changes). Revision 1 to the guide was
Category II. The original regulatory guide was a Category III.
Amendment of 10 CFR 50 to require Periodic Updating of FSAR's ( 2/27/76).

Referred back to staff for additional clarification and definition. Requirement has not been subsequently considered.

8.

Regulatory Guide 1.105, Revision 2 - I nstrument Spans and Setpoints.

9.

Evaluation of Technical Competence of Utility Applicants.

Revision 2 to the guide was categorized as Type II in December 1976. Revision 1 was categorized
as Type I in June 1976 although instrumentation out of conformance to Technical Specifications
Limits was the most frequent abnormal occurrence between 1972 and 1973.
I ssue was referred back to the staff without discussion in 1974. This issue has not subsequently
been considered.

1 0. Regulatory Guide 1.63, Revision 2 - Electrical Penetration Assemblies in Containment Structures for Light Water Cooled Nuclear Power Plants.
Categorized as Type II. The requirement would assure that containment leak design rate is notexceeded during a LOCA.

11, Regulatory Guide 1.52, Revision 2 - Design, Testing and Maintenance Criteria for Engineeri ng Safety Feature Atmosphere Cleanup System Air Filtration and Adsorption Units ofLight Water Cooled Nuclear Power Plants.
Revision 1 was categorized as Type 11. Revision 2 was characterized as Category I. Requirements
contribute to meeting GDC 19 and 61 of Appendix A to 10 CFR 50.

1 2. Regulatory Guide 1.118, Revision 1 - Periodic Testing of Electric Power and Protection Systems.
Categorized as Type I - forefit only. Sets forth requirements for testing of protection systems which
perform safety-related functions.

1 3. Regulatory Guide 1.33, Revision 1 - Quality Assurance Program Requirements ( Operation).

Categorized as Type I - forefit only. Guide addresses acceptable quality assurance practices tomeet the requirements of Appendix B to 10 CFR 50.

1 4. Regulatory Guide 1.143 (for comment, July 1978) - Design Guidance for Radioactive Waste
Management Systems, Structures, and Components Installed in Light Water Cooled
Nuclear Power Plants.
Categorized as Type I - forefit only. Originally considered by RRRC in 1974. Industry resistancedelayed the initial publication of the Guide. As an alternate, the RRRC recommended a Branch
Technical Position. The applicants may appeal the requirement.

43

2. Few RRRC decisions have been implemented onother than a category I basis, requiring "forward
fitting."

ponents "important to safety" commensurate with
the importance of the safety functions they perform.
Although definitive guidelines are not established todelineate the safety importance contributed by thevarious systems and structures, this criterion generally requires that all equipment and structures in a
nuclear powerplant performing a safety function be
subjected to some appropriate quality assurance
standard . 2s

3. The RRRC's categorization of regulatory requirements, guides, etc., has been predominantly
based on engineering judgments. Categorization
criteria for classifying the issues with respect totheir relevance to safety and risk does not exist.

4. The NRC does not have a mechanism or
responsible organization to ensure that RRRC
decisions are implemented.

Appendix B contains 18 criteria that are applied
appliedto the design, fabrication, construction, and testingof safety-related structures, systems, and components of the facility as well as to the managerial
and administrative controls to ensure safe operations.
Unlike the requirements of Criterion 1 of Appendix A,
which apply to all functions that are "important tosafety," the QA program required by Appendix B affects only the safety-related functions and equipment of the facility operation 30 thus presenting classification problems discussed below.

b. Quality Assurance
The Introduction to Appendix B of 10 C.F.R. Part
50 defines quality assurance as:[A)II those planned and systematic actions necessary to provide adequate confidence that a structure, system, or component will perform satisfactorily in service. Quality assurance includes quality
control, which comprises those quality assurance
actions related to the physical characteristics of amaterial, structure, component, or system which
provides a means to control the quality of the material, structure, component, or system to predetermined requirements.

As an applicant and, thereafter, a licensee, theutility is responsible for the establishment and execution of the Quality Assurance Program. The
NRC's requirements for the program are also imposed on nuclear steam system suppliers (NSSS),
architect-engineers, and other subtler suppliers ofequipment, 31 '32 although the NRR reviews only the
QA programs for the principal suppliers. 33 In addition, IE inspects many of the licensees' vendors
through the Licensee Contractor and Vendor Inspection Program described below in the section on"Implementation of QA Programs."
The Standard Review Plans 17.1, "Quality Assurance During the Design and Construction Permit
Phase,"34 and 17.2, "Quality Assurance During
Operations Phase," 35 contain the scope of review
and acceptance criteria for the NRC's approval of
quality assurance programs. These Standard Review Plans refer to a number of regulatory guides
that provide guidance to the applicant for complying
with the criteria of Appendix B. At least 18 regulatory guides addressing various aspects of a QA program exist, most of which endorse industry standards.
For
example,numerousstandards
developed by the American National Standards Institute (ANSI), identified in Series N45.2-1971, "Quality Assurance Program Requirements for Nuclear
Powerplants,"36 and in Series N18.7-1976, "Administrative Controls and Quality Assurance for the
Operational Phase of Nuclear Powerplants," 37 areendorsed as QA practices acceptable to the NRC
for construction and operational phases, respectivel y. Additional guidance to applicants for the designand operation of nuclear powerplants is provided inother Commission publications, including:

The NRC regulations require that applicants establish a Quality Assurance (QA) Program for thedesign, fabrication, construction, and testing of thestructure, systems, and components of the facility
that is adequate to satisfy the minimum requirements of Appendix B of 10 C.F.R. Part 50, "Quality
Assurance Criteria for Nuclear Powerplants and Fuel
Processing Plants," and that this program bepresented in the Preliminary Safety Analysis Report( PSAR), as specified in 10 C.F.R. 50.34(a)(7). Simil arly, 10 C.F.R. 50.34(a)(3) requires compliance with
Appendix A to that same Part, "General Design Criteria for Nuclear Powerplants," for the principal
design criteria, and 10 C.F.R. 50.34(b)(6) requiresthat the Final Safety Analysis Report (FSAR) include
i nformation concerning managerial and administrative controls to assure safe operations, and also
refers to Appendix B for the minimum acceptancerequirements.
As indicated above, Appendices A and B of Part
50 establish requirements related to quality assurance for plant design and operation. The first
five criteria of Appendix A constitute the overall requirements for the General Design Criteria. Criterion 1, "Quality Assurance and Records," requires
quality standards for structures, systems, and com-44

1. Guidance on Quality Assurance Requirements
During Design38and Procurement Phase of Nuclear
Powerplants.
2. Guidance on Quality Assurance Requirements
During the Construction Phase of Nuclear Powerplants 39
3. Guidance on Operational Quality Assurance Requirements During the Operations Phase of Nuclear Plants 40

some of the activities in the QA program. However,a "commitment" is not a regulatory requirement andi s not necessarily enforceable. 50 These commitments are not binding, therefore NRC approval is
not required to cancel or change them. 51
Another deficiency is the lack of specific criteria
for preventive and corrective maintenance programs, surveillance testing, and other operational
activities for ensuring the quality of these activities.
For example, the failure of circuit breakers for certain safety-related equipment has been attributed toi nadequate preventive maintenance programs andsuggests a generic weakness.
This problem iscompounded by the lack of specific qualification re3
quirements and certificationof personnel performing
these activities,
which the NRC staff recently hascertification sought to correct by recommending licensing or

The review conducted by the Quality Assurance
Branch (QAB) in NRC's Division of Project Management is limited to an evaluation of the description of
the applicant's QA program in the PSAR and FSAR,
and an assessment of whether that program cornplies with the 18 criteria of Appendix B. 41 However,no attempt is made by the QAB to determine how or
to what extent the QA programmatic requirements
are applied. This determination is left to the discretion of the applicant,42 who is responsible for identifying safety-related items, 43 determining the extent
that QA requirements are applied to these items,
identifying the activities to which Appendix B ap44
plies, and imposing QA requirements on its con32
The majority of the
tractors and vendors.
applicant's QA programs are found in its implementation procedures, which are not even submitted to
the NRC for review or approval. These implementing procedures, which constitute several volumes of
documents, are retained by the utility. 45
The QAB does not review the applicant's procedures that implement its QA program. 46 Review
of implementation is the responsibility of IE. However, IE does not review the substance of the utility's
procedures to determine their adequacy or to give
NRC approval. The IE review assumes that theutili ty's procedures for implementing its QA program
are adequate, and simply attempts to determine
whether they are being followed.
Deficiencies in the regulations governing QA requirements have been identified in the past by both
NRR and IE personnel. 47 For example, NRC regulations do not require the QA program to be included
as a condition of the license pursuant to 10 C.F.R.
50.54. Consequently, the licensee can makechanges to its QA program and implement procedures without NRC review and approval unlessthe changes involve an "unresolved safety issue"
pursuant to 10 C.F.R. 50.59. 48 The staff has attempted to compensate for this deficiency by obtaining licensee commitments to comply either with
Regulatory Guide 1.33, "Quality Assurance Pro49
grams Requirements for Operation,"or with industry standard ANSI N18.7, "Administrative Controls and Quality Assurance for the Operational
37
Phase of Nuclear Powerplants,"
which include

Although the requirements of Appendix B are
sufficiently broad to adequately address most aspects of acceptable quality assurance programmatic
requirements, one important shortcoming of the regulatory program arises from the absence of a definition of "safety-related," a concept central to theentire structure. Although Appendix B contains
numerous references and applications of "safetygrade equipment," "safety-related equipment," and"equipment required for safety-related functions,"
NRC regulations contain no definition of "safetyrelated" or comparable terms. No other general regulatory guidance for defining or applying theseterms is found and NRC staff members have different interpretations of these terms. 55 Failure todefine "safety-related" has restricted the scope of
the NRC's quality assurance programs. 56 I dentification of particular "safety-related" structures, components, and systems is the responsibility of the applicant utility. The absence of definitional guidance
supports the applicant's narrow interpretation and,correspondingly, decreases the staff's ability to insist that a particular system or function is "safetyrelated."
This lack of clarity has generated staff disagreement concerning the identification of equipment towhich Appendix B should be applied and concerning
the differences and similarities between Appendix A,
which applies to components that are "important tosafety" and require a graduated quality standard,and Appendix B, which imposes a higher quality
standard on the systems and functions to which it
applies.55 This disagreement has frustrated efforts
to formulate a regulatory guide for implementing Ap57
pendix B.
45

The NRC has not encouraged industry development of a classification system of nuclear facility
equipment and systems. The chairman of the
ANS-50 Ad Hoc Committee for ANSI Standard"Equipment Classification for Light Water Reactor
Powerplants" indicated that the NRC opposed sucha standard and would not provide an NRC representative to the committee. The chairman further indicated that he understood that the NRC considered
Regulatory Guide 1.26, "Quality Group ClassificaLions and Standards for Water-, Steam-, andRadioactive-Waste-Containing Components of Nuclear Powerplants," 58 and Regulatory Guide 1.29,"Seismic Design Classification, " r'9 to adequately
classify systems and thus opposed further efforts.
The necessity of providing definitions for determining the applicability of Appendix B was noted as
early as 1972. 60 Currently, however, the only regulatory guide that specifically identifies the equipment
governed by Appendix B is Regulatory Guide 1.29,
which defines seismic category I equipment and requires that all such equipment be identified in section 3.2.2 of the PSAR and FSAR. The determination whether other systems, equipment, or functions
should meet Appendix B requirements is made by
the applicant. Items that the applicant considers
governed by Appendix B are listed by the applicant
in section 17.2 of its PSAR or FSAR, which is theprimary review responsibility of the QAB. This list,
commonly referred to as the Q-list, identifies systems in general. All of the components of thesesystems are not safety-related equipment, however. 61 For example, although the auxiliary feedwater
system was identified on the Q-list for TMI-2, thecontrol component of that system was not considered safety-related and thus not subject to QA
requirements. The interface between safety andnonsafety equipment is determined by the applicant
and not reviewed and approved during the NRC review. The QAB does not review individual Q-lists todetermine their adequacy or acceptability becauseof a lackof technical competency in the review
62
area.
The QAB recently initiated a new practice to help
to ensure the completeness of the list of quality assured equipment. The new QAB practice requiresthat each technical branch review and approve
items on the Q-list that are in their assigned primary
review area of responsibility. 63
The NRC staff position regarding nonsafetygrade equipment has been that it should not contribute to either the mitigation or aggravation of theperformance of the safety grade equipment during atransient or accident. 84 However, some staff actions have been to the contrary. Credit, both im-

plied and explicit, has been given for nonsafetygrade equipment such as pressurizer relief valves,pressurizer
level
i nstrumentation,pressurizer
heaters, refueling water tank level instrumentation,
steam generator level instrumentation, control systems, incore instrumentation, turbine bypass valves,and diesel generator support systems to mitigate atransient or to provide process control information
to initiate operator action. 65 Although this equipment is important to safety, it normally would notappear on the Q-list, and the NRC lacks specificdesign criteria for it. Assessment of the staffs
current practice of relying on nonsafety grade
equipment for the mitigation of the severity of anticipated operational transients may lead to a change instaff policy resulting in additional requirements in the
future. The licensing boards were notified of thiseepossible change the day after the TMI-2 accident.
Crediting nonsafety-grade equipment to the performance of a safety-related function also is clearly
contrary to Criterion 29 of Appendix A, "Protection
Against Anticipated Operational Occurrences," and10 C.F.R. 50.55a. Criterion 29 requires that protection and reactivity control systems be designed toensure "an extremely high probability of accomplishing their safety function." The NRC has established no design criteria for nonsafety-grade
equipment. The reliability of this equipment has notbeen evaluated by the staff, and the single failure
criterion is not applied to nonsafety equipment. 67
Section (h) of 10 C.F.R. 50.55a requires that proteclion systems meet the appropriate edition of the Institute of Electrical and Electronics Engineers (IEEE)
Standard, "Criteria for Protection Systems for Nuclear Power Generating Stations (IEEE-279)." However, the criteria of this standard normally are imposed only for the primary reactivity control system(reactor protection system) and the engineered
safety features systems, which are clearly safetyrelated systems.
Electrical systems and equipment and instrumentation are complex, and this equipment is one of the
major contributors to the safety of nuclear powerplants. Classification of this equipment has beenrecognized as a problem area within NRC since1974. 88 An IE regional office branch chief indicatedthat the classification of electrical systems has been
one of the most neglected areas, and this area ofneglect has permitted safety-related equipment toescape QA requirements. The branch chief identifled the following electrical equipment systems that
perform a safety-related function, but fail to appear
on Q-lists: the process computers and support
equipment used to compute safety limits as defined
i n the technical specifications, control systems, air
46

systems serving safety-related instrumentation andvalves, and instrumentation and monitoring systems.
These systems had not been reviewed as safety related before March 28,1979. 69
The scope of safety-related electrical systems isdelineated in Standard Review Plan 7.1, "Instrumentation and Controls, Introduction."
These systems
are divided into three categories: Basic safety systems that perform a protective function, auxiliary
supporting systems that enable these basic safetysystems to operate, and other systems important tosafety. The latter category was further defined toi nclude:tems, NRC Division of Systems Safety, identified thelack of NRC quantitative reliability criteria for
77
safety-related systems as a problem in 1975.
The
shortcoming of the NRC's current approach was expressed in his recent deposition:

The Single Failure Criterion is an approach to reliability requirements, grossly oversimplified, which
provides a certain degree of reliability such that the
failure of any single component will not fail thefunction of the system.
However, it is applied to systems of vastly different
lity
reliability
with the result that systems complying inevery
ry respect with the Single Failure Criterion canhave greatly different reliability, and that the specification of the Single-Failure Criterion does not provide a well-defined level of reliability. 78[T]hose systems which operate to reduce the probability of occurrence of specific accidents, or tomaintain the plant (including other safety systems)
within the envelope of operating conditions postulated in the accident analyses as being required toassure full protection capability.

Similar criticisms have been advanced by others.
For example, one of the recommendations of a report on the NRC Quality Assurance Program conducted by Sandia Laboratories in 1977 addressed
the need for the addition of reliability analyses in the
QA program. 79 Other recommendations have been
made to the NRC
to incorporate formal reliability
80
safety practices
The NRC did not apply reliability
techniques to safety analyses of the feedwater systems until after the TMI accident, however. 81

Although this definition is broad enough to require
all electrical systems to be designed according to
the requirements of Class 1-E, for example, IEEE296 Standard, single failure criterion, and seismicand environmental qualifications, industry opposition
successfully
has prevented such a classification by71
the NRC.
Both the NRC and industry recognize the need toestablish a graded classification of electrical systems commensurate with their importance to safety. 72 To date, Appendix A has not been implemented and no regulatory guide or branch technical position addressing a graded classification and requirements for such instrumentation or electricalequipment exists. Therefore, electrical equipment issubjected to either the full measure of QA requirements if it is safety-related, or to none at all.
The IEEE Standards Committee has been draftinga standard regarding' the design criteria for safetyrelated surveillance instrumentation (other thanClass 1-E) that have been required by the operator
during normal operating and shutdown conditions of
nuclear powerplants since 1974. A representativefrom NRR cast a negative ballot vote on the proposed standard in 1977. 73 The Office of Standards
Development subsequently was requested by NRR
to develop a regulatory guide to establish criteria forthe design of systems other than Class 1-E, 74 but
manpower limitations have prevented progress inthe development of this guide. 75
Reliability of equipment, namely, predictability that
it will function when needed, is 76
specifically omitted
from the NRC QA requirements.
In lieu of quantitative reliability criteria, the NRC applies the single
failure criterion to achieve reliability. Stephen
Hanauer, currently Assistant Director for Plant Sys-

I mplementation of QA Programs

Assessing the adequacy of Quality Assurance
Programs for nuclear powerplants, the present
director of NRR concluded that the requirements ofAppendix B, guidance presented in regulatory
guides, the NRC-endorsed ANSI standards, and the
SRPs 17.1 and 17.2 are sufficient to ensure their
quality. 82 He acknowledged, however, that properi mplementation may be lacking. The director recognized the lack of inspection and enforcement manpower to police QA implementation. The IE inspection program uses a sampling system for verifying
i mplementation of the licensee's QA program. The
elements of the QA program to be inspected are
identified
in chapter 3500 of the IE Inspection Manu83alThis chapter is divided into modules, whichcontain inspection procedures and include the requirements to be inspected by the NRC inspectors.
The IE is responsible for reviewing implementation
procedures for the utility's QA plan as described in
the PSAR or FSAR. However, as previously indicated, the procedures are neither reviewed for adequacy nor approved by IE.
The Q-Iist is not specific regarding numerous inspection items related to equipment. 84 Therefore,
quality assurance is difficult, and more information isneeded to determine whether the item is acceptable47

or an item of noncompliance or deviation. The IE
regional offices have noted their concerns regarding
i nadequacies of the QA program as approved by
NRR in various memoranda.
I n general, when requested by IE headquarters,
i nterpretations and additional requirements have85
However, the process isbeen provided by NRR.
a cumbersome one. When an inspector needs clarification or an enforcement position for an inspection issue, the normal operating procedure is to address the concerns
through his management to IE
86,87
headquarters,
which evaluates the request and87
Joel Kohler,either resolves it or refers it to NRR .
a Region III reactor inspector, testified that IE headquarters:Moreover, NRR was not requested to concur withthe definition, which had the potential of being used
as acceptance criterion by IE, while not being usedby NRR in approving the QA program.
I n addition to inspecting the licensee's Quality
Assurance Program, IE also inspects some of theli cencee's vendors' QA programs. The Licensee
Contractor and Vendor Inspection Program (LCVIP)
addresses the offsite inspection of manufacturing
activities for components supplied to the licensee bycontractors and vendors; 94 chapter 2700 of the Inspection and Enforcement Manual contains the inspection procedures for NRC inspection. 95 IE Region IV office is responsible for implementing the
LCVIP. Approximately 24 inspectors are responsible for inspecting nearly 250 vendors listed in the
Licensee Contractor and Vendor Inspection Status
Report (White Book). 96 Approximately 180 of thesevendors are inspected annually. Formal criteria do
not exist for the selection of vendors to be inspected. Vendors listed in the White Book are chosenfrom a larger number of suppliers of safety-related
products because they are believed to be more sig97
nificant regarding safety than other components.
Major vendors are inspected more frequently thansubtier vendors.
Norman Mosley testified that the LCVIP is understaffed and greater effort should be devoted to expanding it. Efforts to expand the program wereresisted by the Office of Manpower and Budget,which believed that the program should be aboli shed s8
I nspections for the principal vendors (e.g., NSSS,
fuel manufacturers) are based on the QA programs
that have been approved by NRR through the review of vendor topical reports or the utility's program described in section 17 of the PSAR or FSAR.
Other vendors are inspected according to QA programs that have been accepted by their customers
and by programs approved by the American Societyof Mechanical Engineers. Appendix B criteria areused to judge the acceptability of the vendors' QA
programs. 97 In 1974-75, licensees' vendors wereencouraged to submit topical reports describing
their QA programs for NRR review. This practicesubsequently was discouraged because the topicalreports failed to meet the criteria, such as requirements that an organization must be an applicant,licensee, nuclear steam system supplier, or fuelmanufacturer for the NRC topical report program. 99
Because the NRC regulations do not apply
directly to licensees' vendors and contractors, they
are not subject to enforcement actions delineated inchapter 0800 of the IE Manual and no penalties canbe imposed. However, the vendors and contractors[I]s totally useless from a technical standpoint. The
technical guidance that we (inspectors) get from
OIE headquarters is worthless. They do not havethe final word; NRR does. And it is just a waste oftime in the chain of command.87

Moreover, the response does not necessarily include any affirmative action. For example, Boyce
Grier, Director of IE Region I, requested a clear definition of the need for application of QA measures
to assure that consumables meet standards in Criterion VIII of Appendix B, "Identification and Control
Theof Materials, Parts, and Components."
memorandum noted that enforcement of this criterion was not possible because of the nonspecifici88
ty of NRR approved QA plans. The response from
IE headquarters indicated that no action was warranted because a regulatory guide that would address applicability of Appendix B was being drafted 89 To date, none has been issued.
Another more relevant example is a request by
James O'Reilly, former Director of IE Region I, thatI E issue a bulletin concerning incorrect positioningof safety-related valves. 90 Although the evaluation
by IE headquarters concluded that the eight abnormal occurrences cited in the justification of this request were of safety significance, IE also determined that the proposed bulletin did not meet thecriteria for bulletin issuance, therefore it was not issued.91 The issue identified by the Region I Director
i s related to Appendix B Criterion 10, "Inspection
and Test Control," to make certain that the test activities are performed thereby ensuring satisfactoryequipment performance in service. This same issue
was identified in the Reactor Safety Study as an im92
portant potential contributor to risk.
Finally, in response to a regional office request
for an interim definition of "safety-related" to resolve
an open inspection item, Francis Nolan, IE staff
93
This
member, provided the requested definition.
definition was not promulgated throughout IE.
48

have voluntarily corrected deficiencies identified by
the IE inspections.
The QA programs are contributors to the100"defense-in-depth" concept.
Because mostequipment is designed, fabricated, and tested offsite it appears that licensees' vendor's QA programs, at least the major ones, are as important as
the licensees' programs and should be reviewed,
approved, and inspected according to Appendix B
criteria. In addition, an NRC-approved vendor QA
program would reduce the number of different QA
programs of a vendor requiredby various utilities
101
employing his services.
Such a program would
standardize the QA programs and include Appendix
B requirements.

suring that the technical specification requirements
for limiting conditions for operations were met. Regulatory Guide 1.33, "Quality Assurance Program
Requirements (Operation)," requires that the resultsof completed procedures be routinely reviewed byonsite operating administration. Evidently, such an
audit was not completed. 103 Furthermore, theoperating personnel's failure to recognize that thevalves were inoperative could be attributed to improper implementation of the "tag-out" system indicating operating status, which is governed by Criterion XIV, "Inspection, Test, and Operating Status."
Condensate System Malfunctions

The deficiencies in this system include a clogged
condensate polisher, inadvertent closure of polisher
outlet valves, and failure to remotely open thebypass valve. Surveillance requirements for thecondensate system are not included in the technicalspecifications. The system is identified in the Q-list
for TMI-2, however, and at least part of the systemmeets the requirements of Appendix B. These deficiencies could be related to the lack of frequency
with which the system is tested or to the inadequacy of the test procedures to ensure that the system
will perform satisfactorily in service pursuant to Criterion XI, "Test Control," of Appendix B. In addition,
the lack of specific Appendix B requirements forpreventive or routine maintenance or qualification of
the personnel performing the maintenance may
have contributed to the accident.

I mpacts of Quality Assurance Related Criteria to
TMI-2 Accident and Recovery

The programmatic requirements of Appendix B
are sufficiently broad to encompass equipment performance and plant operation and their failures before, during and after the accident at TMI-2. It isdifficult to assess the role of the QA program regarding this accident, however. Other equipment
present at TMI-2, which performed satisfactorily,
were safety-related but had not been required tomeet NRC's quality assurance requirements.
Although this mitigating equipment probably will beclassified as safety-related and required
to meet102
Appendix B standards in the future,
it was notdesigned, fabricated, or tested pursuant to Appendix B standards, and its success cannot be attributed to the NRC's QA program. Moreover, the deficiencies in the plant's status or condition could be
attributed either to the lack of adequate implementation of applicable QA requirements or to the failure
to require the equipment or personnel action to be
subject to NRC's QA requirements at all. The following discussion lists a number of deficiencies at
TMI-2 and how they can be related to inadequate
quality assurance or quality control requirements.

Reactor Coolant System Leakage

The pressurizer relief valve was leaking at a ratethat exceeded the technicalspecification limit for103
unidentified leakage rate.
The pressurizer relief
valve was not identified as safety-related and thus
was not subject to Appendix B requirements. Thisvalve was part of the pressure boundary and was
designed and constructed according to ASME
codes. However, because it was not identified assafety-related, the electrical control system and instrumentation were not Class 1-E.

Emergency Feedwater Block Valves Closed

Failure to verify that these valves were open aftersurveillance testing could be attributed to failure of
the quality assurance requirement regarding the inspection of activities to ensure that the evolution
from a surveillance mode to an operational mode orfrom a "locked-out" to operational status is accomplished in conformance to procedures. In addition,
contrary to Criterion XI, "Test Control," the procedures for the surveillance tests for the auxiliary
feedwater system did not include provisions for en-

Findings
1. The NRC lacks definitions for "safety-related" asapplied to equipment, systems, structures, and soforth necessary to ensure that Appendix B quality assurance standards are implemented consistently. The consequence has been an ad hoc,
uncontrolled application of safety-related requirements to equipment outside the reactor protec49

whether or how they are being implemented by the
NRC staff108
Historically, the debate over generic issues has
generated considerable disagreement over the precise number of issues that existed. In 1975 the
NRC's Technical Safety Activities Report identified
225 technical safety activities warranting consideration 1 07 These, in turn, were grouped according toareas of review in which the generic item should be
addressed, such as reactor safety, engineering, site
safety, containment safety, and were categorized interms of the priorities for their consideration andresolution108 A year later, during hearings before
the Joint Committee on Atomic Energy, this list wasreviewed and was characterized by the NRR as not
representing "a list of safety concerns that must be
resolved to assure the basic safety of continued
operation of reactors. Rather, they deal with more109
precisely defining the safety margins in the plant."
I n January 1976, allegations by a departing NRC
staff member before the Joint Committee on Atomic
Energytt° concerning the NRC's reactor safety review process resulted in the identification of 24
safety issues that he felt needed to be resolved before the Nation proceeded with commercial nuclear
power. Again, the NRC's response to these allegations was to assert that none were technical issues
that had not been adequately considered by thestaff."' During the same hearings, three General
Electric (GE) employees identified
52 additional and112
related primarily tosimilar safety concerns
boiling-water reactors (BWR). The Commission's
evaluation of these issues concluded that they,
however, "provided no new insights into any reactor
113
safety issue."Later that year a number of NRR staff members
posed another 27 problems whose priority, progress, or resolution was, in their opinion, unsatisfactort' 114 The director of NRR concluded that 26 of
the 27 issues raised did not warrant revisions to
any of its existing licenses, or changes in current
staff priorities regarding the reso l ution of the issue.
Congress obviously was not satisfied with the
NRC's treatment of the generic issues problem. In
1977, it amended the Energy Reorganization Act of1974 to include a new Section 210, which instructed
the Commission to develop a systematic means ofidentifying and dealing with generic issues:
The Commission shall develop a plan providing forspecification and analysis of unresolved safety issues relating to nuclear reactors and shall takesuch action as may be necessary to implement
corrective measures with respect to such issues.
Such plans shall be submitted to the Congress onor before January 1, 1978 and progress reports
shall be included in the annual report of the Com15
mission thereafter 1tion system and the engineered safety featuressystems.
2. The NRC has no criteria for quality assurance
standards for components commensurate with
their safety function as required by Criterion 1 of
the General Design Criteria, Appendix A.
3. Appendix B lacks explicit criteria for maintenanceand other operations and certification of personnel performing these activities.
4. The NRC lacks quantitative reliability methodology in QA program requirements and safety analyses evaluations.
5. Sections 17.1 and 17.2 of the Standard Review
Plan lack acceptance criteria and review procedures for the list of items that conform to Appendix B standards.
6. The Quality Assurance Program is not a condition of the operating license.
7. Some of the TMI-2 plant deficiencies can be related to inadequate quality assurance or quality
control requirements.
c. Generic Issues
Background

Generic issues are general technical matters reating
to safety, safeguards, or environmental asl
pects of nuclear powerplant design, construction, or
operation that are applicable to all or a subset of allplant types. Most generic issues are identified in
the review of individual applications. However, because generic issues are not limited to a specificplant, they are not handled as part of an individualli censing case. Categorization of an issue as generi s typically delays its resolution. Because these issues are treated on a general basis and are not regarded as impediments to individual plant licensing,
little incentive exists for their prompt resolution.
I mpetus for addressing generic issues comes primarily from the Advisory Committee on Reactor
Safeguards, which since 1972 has identified theseissues during its review of utility applications to construct or operate nuclear powerplants. The advisory committee also serves as the primary impetus fortheir resolution; typically when "they [ACRS] quit
105
asking questions we [NRR] quit answering them."Moreover, the advisory committee deems a generici ssue to have been "resolved" when it has been addressed in a regulatory guide, the Standard Review
Plan, an industry standard, or branch technical positions. The advisory committee's definition of the"resolution" of a generic issue does not consider its
implementation, and the committee does not follow
up on "resolved" generic issues to determine50

As a result, the Commissioners directed NRR toinstitute a program to define, categorize, andmanage generic technical activities on a systematic,
integrated basis. This program was reported by the
NRC in its 1978 annual report to Congress. 116 A
Technical Activities Steering Committee, comprisedof members of upper level NRC management, wasestablished to manage this program. The committee initially considered over 355 generic issues, andreduced that number by combining identical andsimilar issues and eliminating those deemed to require policy decisions rather than a generic technical solution. By May 1977, the committee had identified, and categorized 133 generic tasks.

that its program was considerably broader than that
required by Section 210, and thus that its future annual reports would focus on the kinds of "unresolved safety issues" referred to by that statute,which, by definition, are the most significant subset
of generic licensing issues. The steering committee
subsequently developed the following definition ofan "unresolved safety issue" in preparation for theCommission's 1979 Annual Report to Congress:
An Unresolved Safety Issue is a matter affecting
several nuclear power plants for which it is likelythat actions will be taken to (1) compensate for a
possible major reduction in the degree of protectionof the public health and safety, or (2) provide a potentially significant decrease in risk to the publichealth and safety 1 19

The steering committee additionally establishedthe following priorities for the resolution of these issues:

Using this definition and techniques such as probabilistic risk assessment, 120 the steering committee identified 14 generic issues that met its definition
121
and thus that should be reported to Congress.
The steering committee then submitted a draft ofthe122
Annual Report to the Commissioners for approval , which was discussed in a public meeting
between the staff and Commissioners. During thatmeeting, four of the five Commissioners expressed
dissatisfaction with the steering committee's defini23
tion 1
Concern was expressed that the definition
must be compatible with the continued operation ofexisting plants. The Commissioners thus requested
the staff to revise its proposed definition which waschanged to read as follows in the NRC's 1979 reportto Congress:

Category A-Generic technical activities judged by
the staff to warrant priority attention in terms of
manpower and funds, either individually or combined, to attain early resolution. These matters
i nclude issues whose resolution could (1) provide asignificant increase in assurance of the health andsafety of the public or (2) have a significant impact
upon the reactor licensing process.
Category B-Generic technical activities judged by
the staff to be important in assuring the continued
health and safety of the public but for which early
resolution is not required and for which the staff
perceives less significance than category A mattersi n relation to safety, safeguards or the environment.

An Unresolved Safety Issue is a matter affecting a
number of nuclear power plants that poses important questions concerning the adequacy of existing
safety requirements for which a final resolution has
not yet been developed and that involves conditions not
ff likely to b 24
acceptable over the lifetime ofthe panl tsaected .

Category C-Generic technical activities judged by
the staff to have little direct or immediate safety,
safeguards, or environmental significance, but which
could lead to improved staff understanding of particular technical issues or refinements in the licensing
process.

The Commission's 1979 report also added three
generic issues to the list proposed by the steeringcommittee, raising the total number of "unresolved
safety issues" to 17.

Category D-Proposed generic technical activities
judged by the staff not to warrant the expenditure ofmanpower or funds because they have little or noi mportance to (1) the safety, environmental, or safeguards aspects of nuclear reactors or (2) to improvi ng the licensing process can be attributed to theactivity.

Limited manpower and funding have resulted incontinuing staff efforts to prioritize generic issuea inorder to assign available resources for their resolution. Accordingly, the steering committee rated thei ssues it had by assigning points to each generictask plan. Prior to the point assignment, some task
plans were combined with others,
resulting in a total
125
rating of 124 task action plans.

The steering committee establishedtask plans to117
resolve only category A issues.
Although task
problem descriptions have been published for theremaining categories, no plan for their resolution has
yet been established. 118
In a letter transmitting the "NRC Program for the
Resolution of Generic Issues Related to Nuclear
Power Plants" to Congress, the NRC pointed out

The steering committee's ranking of the generictask plans, which was endorsed by the director of
NRR, dictated
126 where available resources should be
expended.
For example, those ranked in the top
51

(2) Conditions of minor safety significance resulting
from marginal engineering practice;(3) Conditions having known safety significance but
which have a low probability of occurrence andmarginally acceptable consequences (approaching but less than 10 CFR 100 limits);(4) Conditions that could lead to low probability accidents of serious consequences whose correction would require extensive evaluation or possible substantial plant modifications, but where thedelay in implementing correction can be justified
on grounds of improbability for a limited period
of delay;(5) Conditions leading to events having a high probability of occurrence and possibly serious
consequences whose correction should occur
prior to plant operation, but where consequences can be acceptably mitigated by a decrease in power or other operational restrictions
until corrective modifications are completed orwhere the occurrence likelihood is reduced byother means.

20 including the 17 issues identified as "unresolved
safety issues" in the Commission's 1979 report toCongress, were deemed to be priority items warranting the commitment of sufficient resources toassure their resolution in a timely manner. Nineteentask action plans were established for these 17 issues. The steering committee also recommended
that expenditures of resources and manpower on
the 80 least pressing projects be halted. Finally, it
was suggested that the other 24 tasks could be assigned resources at the discretion of the NRR division director in his area of responsibility.
Although the precise number of generic issues
has fluctuated as some are redefined or recategorized and others identified for the first time in licensi ng actions or elsewhere, some progress has been
made in this area. Mike Aycock, the Secretary to
the Technical Activities Steering Committee, indicated that three category A generic issues were completed during 1978. Former NRC Chairman Hendrie
has recognized the need to review the generic issues problem. 127 Still, actual progress in this area
has been limited. This remains an area requiring
substantially more attention and progress than it
has received to date.

I nstances of conditions falling into the first three
categories can be numerous without creating significant jeopardy to public safety.
Only a few items in Category 4 would be tolerable
at any one time because the cumulative effectwould be unacceptable.

A limited number of items in Category 5 might betolerable for varying periods of time depending
upon the degree to which (a) operational restrictions can effect a reduction in the event probability
to a tolerable level or (b) surveillance can provide
an acceptable means of mitigating risk.

I mpact of Generic Issues on Licensing Process

The NRC staff has determined that the construction and continued operation of nuclear powerplants
without resolution of generic issues does notpresent an undue risk to public health and safety.
This judgement is shared by the Advisory Committee on Reactor Safeguards and the Atomic Safety
and Licensing Board. 128 Thus, while the licensing
boards have considered generic issues129in their
hearings, such as the hearing on TMI-2,
North
Anna Units 1 and 2, 130 and River Bend Units 1 and
2,131 these unresolved matters have not deterred
their licensing actions.
I n response to a question by the Joint Committee
on Atomic Energy whether there is any limit on thenumber or type of unresolved safety issues thatshould be permitted to remain unresolved at any
one time before nuclear powerplant operation
should be curtailed, the ACRS responded:

A full quantitative basis for making judgements regarding the type and number of unresolved safetyi ssues which are acceptable is difficult to develop
but should be pursued. In the current approach,major dependence is placed upon reaching a conclusion through engineering judgements that theoverall risk from the plant would not be significantly
i ncreased by the existence of the unresolved safetyissues in question .w

The continued existence of unresolved safety issues in the regulatory process has been justified by
the NRC's qualitative judgment that the likelihood ofsignificant consequences associated with postulated
hypothetical accidents related to these issues is scl 33
ceptably small for continued licensing activities.
92
I n the past, the Reactor Safety Studyhas beenreferred to as confirmation that the design of eachlicensed plant provides reasonable assurance thatits operation does not present an undue risk to the
public health and safety. l34 More recently, however, a number of problems with the application of theReactor Safety Study in the licensing arena havebeen identified.
These are well documented in the135
and include adequacy of the study's
Lewis study

The important word in the preceding question istype rather than number. Most unresolved safetyissues may be classified into the following
categories of increasing significance beginning withthose of low consequences:(1) Conditions with potential for degrading systemsafety but for which it is judged that further
theoretical and/or experimental evaluation will
demonstrate no safety significance;52

data base, the validity of its assumptions, inability toverify results, the inability to quantify all contributors
to risk, the value-impact of risk reduction, etc. As aresult of the Lewis study, the NRC revised
136 its policy
regarding the Reactor Safety Study.
Consequently, the application of the Reactor Safety
Study's numerical categorization of absolute risk nol onger serves as a basis for regulatory decisions,and the safety significance of generic issues is now
judged on a relative risk basis.120

Human-Machine Interfaces

This issue was identified by Stephen Hanauer in
1975143
and by the resigned GE employees in
144
1976.
The advisory committee recommended
evaluation of existing operator training and testingprocedures to demonstrate that existing programs
are effective. The committee noted the lack of a
feedback system to incorporate the experience of
operating plants in the preparation of operating andtraining prpcedures at other plants, and recommended that the NRC give increased attention tooperator understanding
145 and implementation of emergency procedures.
In 1978, the advisory committee recommended that high priority be given to
the research program for man-machine interfaces;that the Commission explore advantages and disadvantages of computer controlled automation; andthat a systematic review of operational experienceand accidents
in U.S. and foreign plants be under146
taken.
These general issues do not appear on
any NRR generic list, however, and work on thepossibly related Task Activity B-17, "Criteria for
Safety-Related Operations" which would address
time criteria
for safety-related actions has been126
suspended.

Generic Issues Related to the Three Mile Island
Accident

The Special Inquiry Group's (SIG) considerationof generic issues related to the accident at Three
Mile Island sought to identify some illustrative examples which had the potential to prevent or alter thatcourse of events. As will be noted, a number of issues discussed herein have not been categorized
as generic issues by the NRC. Moreover, because
no one knows how or when issues recognized by
the NRC as generic will be resolved, how or when
they might be implemented, or how they might havei mpacted the relevant human factors contributing to
TMI-2, the undertaking presented here is a highly
speculative endeavor.

Instrumentation to Follow the Course of an Accident

Instrumentation to Detect Gross Fuel Failures

The purpose of such instrumentation is to ensurethat appropriate parameters are monitored during
an accident so that operators will have sufficient information available to mitigate its consequences.
The advisory committee has emphasized the needto establish requirements forsuch instrumentation147
to the NRR staff since 1969.
The issue was identified by the Technical Steering Activities Committee
as Generic Task A-34, "Instrumentation for Monitori ng Radiation and Process Variables During Accidents." However, the advisory committee considered the issue to be "resolved" with the publication of Regulatory Guide 1.97, "Instrumentation forLight-Water-Cooled Nuclear Power Plants to Assess Plant Conditions During and Following an Accident," even though this regulatory guide has notbeen implemented in any operating plant t48 and thei ndustry has evidenced
considerable resistance to149
its implementation.
As a result, neither the steeri ng committee nor the Commission regarded this tobe an "unresolved safety issue," and it was not included in the Commission's Report to Congress,
even though the Commission was told that the issue
could be critical to reducing the hazards associatedwith an accident. 1 50

This issue, identified in 1972 by the ACRS,137
deals with the establishment of instrumentation criteria to detect severe fuel damage (e.g., melting);
the staff has completed work concerning limited fueldamage only. This item does not appear on thepresent NRC generic issue list.
Interruption of ECCS After LOCH

This issue arises in conjunction with the generici ssue "Loss of Offsite Power Subsequent to Manual
Safety Injection Reset Following a LOCA (Loss of
Coolant Accident)." 138 In 1976, the Advisory Committee recommended that further studies of the probabilities and 139
consequences of such an event bemade by staff.
To some extent, the staff has addressed the aspect of the original issue of emergency core cooling system reset following loss of offsite
power. The issue has not appeared on any advisory committee generic list, however, and the staff has
never required that an emergency core cooling system design be capable of withstanding an interruption over a prolonged period of time andstill meet
140-142the relevant safety performance criteria.
53

i mplemented on a case-by-case basis in accordance with a determination by Regulatory Requirements Review Committee.

Systems Interactions

This issue addresses the effect of one system
failure on another system (common cause failures)and constitutes a combination of a number of related generic issues, such as nonrandom failures, control system failures, nuclear steam system-balanceof-plant interfaces, and interaction between control
and protection systems.
System interaction was identified as an issue ofconcern as early as 1974. 151 Although not identified
by the NRC staff as an "unresolved safety issue," it
was added to the list of such generic issues by theCommissioners prior to the transmissionof the124
NRC's Report to Congress in 1979.
It is identified
as an unresolved safety issue for Generic Task
Force A-17,"System Interactions in Nuclear Power125
Plants."However, because of resource limitations, this issue only addresses pressurized-water
reactor (PWR) transients and not accidents.

Noncondensibles in the Reactor Coolant System

Though not identified as a generic issue, the production of noncondensible gases in a loss-ofcoolant-accident was discussed as early as 1968 invarious advisory committee meetings concerninghydrogen from failed fuel and nitrogen from accu147
Noncondensible gases affect themulator tanks.
natural circulation capability of the primary coolant
system and provide the potential for local core
blockage resulting from a gas bubble. To date,however, neither the NRC nor vendors' analyses
have addressed the effects of noncondensible
gases during a LOCH.
Hydrogen Control in Containment

This has never been considered a generic issue.
Concerns
expressed by the advisory committee in147
1967
resulted in inerting some boiling-waterreactor (BWR) containment atmospheres, although
no pressurized-water reactor (PWR) containments
are inerted. Regulatory Guide 1.7, "Control of Combustible Gas Concentrations in Containment Followi ng a Loss-of-Coolant Accident," Revision 2, wasrevised in November 1978, and categorized by Regulatory Requirements Review Committee as a requirement that should be imposed only on a prospective basis. Several pressurized water reactors
depend on purging to control hydrogen gas concentration. A proposed amendment to 10 C.F.R. 50 torequire inerting of containment atmospheres andstandards for combustible gas control
systems
158
were published in November 1978.

Operator Error and Actions

These issues were broadly addressed by allega144
tions of the resigned GE employees in 1976.
Specific areas of identified concern included designof control rooms, control room simulators and procedural requirements. Task Action Plan B-17 "Criteria for Safety-Related Operator Action," has been
halted due to its low priority ranking by the Technical Activities Steering Committee.126 Human error is
not included in the NRC accident analyses evaluation 52 and based on the TMI-2 accident, this issue
requires immediate attention by-the NRC in its safety analyses of transients and accidents.

1

Containment Isolation

I n 1976, a former NRC employee criticized theCommission for its failure to deal with the isolationof low pressure153
systems connected to the primarycoolant system.
Initiating signals for containmenti solation has not been a generic issue, however.
The advisory committee considered the need fordiverse signals to initiate containment isolation forWestinghouse plants,
but not for Babcock & Wilcox
147
and other vendors.
The Commission staff acknowledged lackofdiversesignals for B&W equip154
ment in 1976,
and indicated in a 1978 meetingwith Metropolitan Edison that "operating procedures
will have to be revised to show manual closure of
the containment
isolation valves is required after ac155
cident."The staff's position requiring "diversity
i n the parameters sensed (i.e., types of isolation signals) for the initiation of containment isolation" wasexpressed in Regulatory Guide 1.141, which is to be

Qualification of Equipment

157

This was identified as Issue 25
during the 1976
staff discussionofgeneric safety issues.
Thereafter, two applicable Task Activities-A-21," Main Steamline Break Inside Containment" and A24, "Qualification of Class I-E Safety Related
Equipment"-reported on this issue. 158
I n response to a petition from the Union of Concerned Scientists, IE requested
licensees to review
159
qualification of equipment;
the issue was identified as an "unresolved safety issue," in theCommission's 1979 Report to Congress. In March
1979, the ACRS declared the issue "resolved," however, because critical components were covered byRegulatory Guides 1.40,1.63, 1.73 and 1.89 and IEEE
54

Standards106
382-1972, 383-1974, 317-1972, and323-1974.
This issue has not been resolved by
NRC.

control systems
have not been reviewed in detail by
161
the NRC staff.
Findings

Capability of Hermetic Seals on instrumentation andElectrical Equipment

1. Lack of NRC priority to address generic issues
has resulted in resolution of only two "unresolved
safety issues," and neither of these have beeni mplemented. Most NRC efforts on generic issues have been expended on prioritizing the listof issues for the allocation of limited resources.
2. Responsibility for resolving generic issues andthen implementing the resolution is widelydispersed throughout the NRC, primarily in various areas within NRR.
3. Generic issues as conditions with a schedule forcompletion have not been identified in construction permits or operating licenses. Consequently,
there is no impetus or incentive to effect theirresolution.

The Commission's failure to deal with this issue
was the subject of one of the critical allegations
made by the resigned GE employees in February
1976144 The advisory committee subsequently
i dentified this as a generic issue in April 1976. The
relevant task force, Task Activity C-1, "Assurance ofContinuous Long-Term Integrity of Seals on Instrumentation and Electrical Equipment," has beensuspended, however. 126 The extent that the failureof hermetic seals inhibited recovery from the TMI-2
accident cannot be determined until they can be examined inside containment.
Single Failure Criterion and Reliabilityd. Technical Qualifications

In a memorandum to Commissioner Gilinsky in
1975, Stephen Hanauer stated that the "NRC has
not established quantitative reliability criteria forsafety-related systems." 1 43 Similarly, one of theallegations raised by the resigned GE employees
was the Commission's lack of reliability data on systems. l 44 This issue was included among the list ofgeneric issues that certain Commission staff
members claimed
114 were not receiving sufficient attention in 1976.
The single failure criterion is rel ated to several other generic issues such as passive failures, definition of safety-related equipment,
systems interactions, nonrandom failures, andoperator error. This issue was not included in the
NRC generic list, but is accepted by the NRC staff
as a satisfactory alternate to quantitative reliability
analyses.160 Moreover, the criterion is applied toonly the safety related components and systems.
Presently, emergency core cooling system reliability
is addressed in Task Activity C-11. Expenditures on142both these tasks, however, have been halted.

Background

Section 182 of the Atomic Energy Act of 1954, as
amended, provides that each applicant for a license:[S]hall specifically state such information as theCommission, by rule or regulation, may determine
to be necessary to decide such of the technical ...
qualifications of the applicant . . . as the Commisl 2
sion may deem appropriate for the license. s

NRC regulations, in turn, require that the NRC findthe applicant to be technically and financially qualified prior to the issuance of a construction permit oran operating license. The regulation governing thei ssuance of an operating license requires that theCommission find that "[t]he applicant is technicallyand financially qualified to engage in the activities
authorized by the operating license163
in accordancewith the regulations in this chapter."
The regulation covering construction permits requires that thepermit be subject164
to the same conditions as an
operating license.
I n addition, the regulations
reiterate these conditions as a common
standard for165
licenses and construction permits.
The technical information required for theCommission's finding that the applicant is technicallyqualified must be included in the applicant's Prelimi nary Safety Analysis Report (PSAR) submitted as apart of the construction permit application, and in
the Final Safety Analysis Report (FSAR)
submitted
166with the operating license application.
The regulations require that the FSAR include additional information related to the applicant's organi-

Systematic Review of Normal Plant Operation andControl

Although this was identified as an issue
114of concern by a critical NRC staff report in 1976,
no positive efforts were initiated to include the safety significance of control systems in the NRC review process. This issue has since been marginally addressed as part of Generic Task A-17, "System Interactions in Nuclear Power Plants." The NRC generic list does not include this issue, however, and55

zational structure not provided at the construction
permit stage, including the following:

qualifications, provided his understanding of theseconcepts:

The applicant's organizational structure, allocations
or responsibilities and authorities and personnel
qualifications requirements.167

I think it's one in which the applicant has established an appropriate organization with adequately
defined responsibilities, with people technicallyqualified to implement those responsibilities to carryout their responsibilities indesign, construction,and operation of the facility.heManagerial and administrative controls to be used
to assure safe operation. Appendix B, "Quality Assurance Criteria for Nuclear Power Plants and Fuel
Reprocessing Plants" sets forth the requirements
for such controls for nuclear power plants . . . .
The information on the controls to be used for anuclear power plant "shall include a discussion of
how the applicable requirements of Appendix B will
be satisfied.1

Key plant staff is reviewed in considerable detail,i ncluding the organization, numbers of people assigned to each position, the qualification requirements for each position and the actual qualificationsof key personnel assigned to the plant staff.' 80 This
review focuses on the actual qualifications of key
management and professional personnel as reflected in their individual resumes, but only on the moregeneral qualification requirements for other personnel, such as technicians, maintenance and repairmen. Key personnel include the radiation protection
manager, members of the Plant Operations Review
Committee, nuclear engineers, plant superintendents, and shift foremen. Plant staff are identified
by position and their qualification requirements areusually contained in the technical specifications of
the operating license.
After the NRC review of the technical qualifications of key personnel during the operating license
review, the licensee thereafter may change these individuals without NRC review or control. Thus, inessence, the NRC approves the functions of the position rather than license an individual for that posi81
Moreover, the review of the applicant's
tion1
technical qualifications to conduct operations as set
forth in section 13 of the Standard Review Plan does
not include all important personnel who potentiallycontribute to the applicant's overall technical qualification capability. For example, qualifications ofquality assurance personnel and testing personnel
182
are addressed in other review areas of the SRP.
The Quality Assurance Branch examination inapproving the plant operating staff in SRP 13.1.2 includes the position titles, operator licensing requirements, and the numbers of operating personnel assigned per shift. Qualifications of testing personnel
i nvolved in the initial test program are addressed in
section 14 of the Standard Review Plan and notusually reviewed by the same Commission staff person who reviews the applicant'sorganization and183
staff for technical capability.
Because the QAB
has the responsibility to review the initial test pro
grams, informal discussions involving the qualifications of test personnel and other plant staff184
occasionally transpire between branch members.
Fi-

NRC regulations also require that each applicant fora license authorizing operation include its proposed
technical specifications which, among other things,
provide for administrative controls, defined by theregulations to consist of:[T]he provisions relating to organization andmanagement, procedures, recordkeeping, review
and audit and reporting necessary to assure opera169
tion of the facility in a safe manner.

This information is evaluated by the Quality Assurance Branch (QAB) of the NRC's Division of Proj ect Management, whose review is based on the acceptance criteria set forth in the Standard Review
Plan (SRP). 170 In some instances, the Standard Review 171
Plan itself contains criteria for particular issues.
The SRP also refers to other documents
for guidance. For example, the SRP refers to the"Standard for Administrative Controls for Nuclear
Power Plants" for guidance on requirements relating
to operating organizations,rules of practice, and on172
site review criteria.
The AEC's "Utility Staffing
and Training for Nuclear Power" offers additional
guidance as to the requirements acceptable to thestaff formanagement and technical support organi173
zation.
Qualifications for the applicant's personnel
also are contained in Regulatory
Guide 1.8, "Person174
nel Selection and Training"which, in turn, refers
to the "Selection and Training of Nuclear Power
Plant Personnel," publishedby the American Nation175
al Standards Institute,and to the previously
mentioned"Utility
StaffingandTraining for Nuclear
176
Power".
Notably absent from all of these documents are
any qualitative guidelines or detailed regulatory criteria by which the various
technical qualifications
177,178
should be assessed.
Similarily, a definition for"technical qualifications" is lacking. Frederick Allenspach, who is the only NRC reviewer assigned
responsibility for review of an applicant's technical56

As a result of Atomic Safety and Licensing Board
deliberations concerning the staff's determination ofan applicant's technical qualifications, efforts were
i nitiated in December 1978 to develop a more systematic
approach to evaluate applicants' qualifica19o,196
tions.
However, efforts by the QAB to establish a formal procedure to provide a more substantechnical qualifications
tial basis for determining 194
QAB recommended
have not been successful.
that procedures be formalized to include IE input tothe project manager and that the project manager
be assigned the responsibility for making the findingthat the applicant is technically qualified. QAB
further recommended the project manager's
responsibilities be addressed in the Licensing Pro197
To date, these recomject Manager Handbook.
mendations
have
not
been
implemented by the
198
DPM.

nally, IE only verifies that the individual's experienceand qualifications meet the general qualification requirements of the position which have been identified by the licensee and approved by NRR.
A review of an applicant's technical qualifications
does not include requirements that relate to applicant experience in either the design, construction,
or operation of nuclear powerplants; 185 nor does
the review cover the applicant's capability to perform routine and emergency operations of the nu186
Although some Commission
clear powerplant.
staff members have recommended that past performance in operating a nuclear power facility be madean explicit and important consideration in theevaluation of an applicant's technical competence,
their superiors in 187
the staff did not concur in theserecommendations.
Similarly, the applicant's capability to respond to an emergency situation was
not considered prior to March 29, 1979, although
the NRC is now evaluating licensee's capability tocope with operations during an accident. This assessment, however, is vested elsewhere in the review process. Finally, until recently the technicalqualifications review has not explicitly considered
the qualifications of the architect-engineer, the nuclear steam system supplier, or other contractors
and consultants employed by the applicant to execute its responsibilities. However, a recent revision
to the Standard Review Plan includes more definitive review responsibility with regard to qualifications of these personnel0
Although the NRC must make a finding that theapplicant is technically qualified to engage in thedesign, construction and operation of nuclear
powerplants, neither the basis for this determination
nor the assignmentof responsibility for making it are
191
well defined.
The QAB provides the principal input into the Safety Evaluation Report regarding thetechnical qualifications of the applicant based on thereview of the applicant's organization structure 19
inchapter 13 of either the PSAR or the FSAR.
However, this review is quite narrow in scope bycomparison to the regulatory requirements and thecomprehensive finding made by the Commission in
the Safety Evaluation Report. The licensing project
manager "as a matter of course" makes the final
overall judgmental determination that the applicant
i s technically qualified, using the QAB input fortechnical qualifications and Quality Assurance Programs, other review inputs, and his own judgment
177,193
based on his interactions with the applicant.
No guidance or acceptable criteria are available toguide the project manager in this finding, however.194.195

Technical Qualification Review of Metropolitan
Edison Company

The review of the technical qualifications ofMetropolitan Edison Company to operate TMI-2 appatently was not performed according to the Standard Review Plan.
This can be attributed
to9,200
the NRR revision to office letter number
which
directed the staff not to document the deviations
from the Standard Review Plan for TMI-2 and otherplants. The specific acceptance criteria used in thereview of TMI-2 were nonetheless the same as
those contained in the Standard Review Plan, because the SRP reflected past review practices regarding requirements for the plant staff, such as Regulatory Guide 1.8 and ANSI Standards N18.7 andN18.1. The qualifications of the architect-engineer
and vendors were not, however, reviewed. 201
Frederick Allenspach, who has reviewed approximately 40 applications to evaluate the applicant's
technical qualifications, compared Met Ed favorably
to other applicants. As he stated to the SIG:

I think in general I would have rated this home office probably average to above, and their plantstaff, I think would be superior, superior to moststaff 2Findings
1. Although the NRC must make a finding that theapplicant is technically qualified to engage in thedesign, construction, and operation of nuclear
powerplants, acceptance criteria and assignmentof responsibility within NRC are not well defined.

57

2. The applicant's experience or past performancei n the design, construction or operation of nuclear powerplants is not explicitly considered by
the NRC in its evaluation of the applicant's qualifications.
3. The applicant's technical qualification is based inpart on the qualifications of key individuals identified in the plant staff organization. The NRC does
not review or approve the personnel changes forthese key positions after the license is issued,
however.

4. The review of plant staff qualifications that contribute to the overall technical qualifications of theapplicant is dispersed among several NRC review
disciplines.
5. The capability of the applicant to respond to an
emergency situation was not considered as partof the NRC review of technical qualifications prior
to the TMI-2 accident.

58

REFERENCES AND NOTES
32'the director of regulation reported directly to theCommission and was responsible for the regulation ofcommercial nuclear facilities. The directors of the major
offices reported to the director of regulation and not to
the Commission. Currently the major office directors
report to the Commission.
2
lnformation Report to the Commissioners from L. M.
Muntzing, "Regulatory Program for Minimizing and Controlling Ratcheting," SECY-R-74-95, December 19, 1973;
I nformation Report to Commissioners from L. M. Muntzi ng, "Regulatory Requirements Review Committee,"
SECY-R-74-132, March 5,1974.
3
NRC, "Standard Review Plan for the Review of Safety
Analysis Reports for Nuclear Power Plants-LWR Edition," NUREG-75/087.
4
Case dep. at 226.
5
Varga dep. at 6, 70; Hanauer dep. at 92.
6
Case dep. at 242.
7
1d. at 227.
8
Varga dep. at 27.
9Case dep. at 229.
1
OVarga dep. at 28.
"Case dep. at 228.
12/d. at 236.
13
Varga dep. at 239.
14
1d. at Exhibit 1004.
'5!d. at 40.
16
1d. at 39.
171.
at 43.
18
14. at 56.
19
lnformation Report to the Commissioners from H.
Denton, "Improving the Process for Determining the Needfor New Reactor Requirements," SECY-79-8, January 2,
1979. (Hereafter referred to as SECY-79-8).
20Case dep. at 230, 239.
21 Information Report to the Commissioners from H.
Denton, "Improving the Process for Determining the Needfor New Reactor Requirements," SECY-79-8, January
2,1979.
22
Letter from E. G. Case to S. D. Freeman, Subject:
Response to Freeman Letter of March 8, 1978 to Chairman Hendrie, dated April 8,1978; Varga dep. at
14.
23
Varga dep. at 58.
24
1d. at 57.
25
Case dep. at 230.
28
Varga dep. at 21.
27
Memorandum from R. Boyd, NRC, to H. Denton,"I mplementation of New Regulatory Requirements
Recommended by RRRC and Approved by the Director,
NRR," February 10, 1978.
28
Memorandum from D. K. Davis, NRC, to Systematic
Evaluation Program Branch Members and D. Ziemann,"Incorporation of Regulatory Requirements Review Committee Category 2 and 3 Items into Systematic Evaluation
Program Review," April 6, 1979.
29
Haass dep. at 36, 40.
30
Haass dep. at 39; Gilray dep. at 52.
31
Haass dep. at 20.

Gilray dep. at 52.
Gilray dep. at 82.
34
NRC, "Standard Review Plan for the Review of
Safety Analysis Reports for Nuclear Powerplants-LWR
Edition," NUREG-75/087, Section 17.1.
35
1d. at Section 17.2.
36"American National Standard Quality Assurance Program Requirements for Nuclear Powerplants," ANSI
N45.2-1971.
37"American National Standard Administrative Controls
and Quality Assurance for the Operational Phase of
Nuclar Powerplants," ANSI N18.7-1976/ANS-3.2.
38
U.S. Atomic Energy Commission, "Guidance on
Quality Assurance Requirements During Design and Procurement Phase of Nuclear Powerplants," Revision 1,
WASH-1283, May 24, 1979.
39
U.S. Atomic Energy Commission, "Guidance on
Quality Assurance Requirements During the Construction
Phase of Nuclear Power Plants," WASH-1309, May 10,
1974.
40
U.S. Atomic Energy Commission, "Guidance on
Operational Quality Assurance Requirements During the
Operations Phase of Nuclear Powerplants," WASH-1284,
October 1973.
41
Gilray dep. at 40, 56.
42k1 at 45.
43
Haass dep. at 28.
"Id. at 63.
45Ruhlman dep. at
9.
48
46; Haass dep. at 7.
Gilraydep.
at47
Ruhlman dep. at 19; Gilray dep. at 75.
"is is in contrast to operator requalification programs, Appendix A to 10 C.F.R. Part 50, "Safeguards
Contingency Procedures," Appendix C to 10 C.F.R. Part73, and reactor containment leakage testing procedures,
Appendix J to 10 C.F.R. Part 50.
49
NRC, Regulatory Guide 1.33, "Quality Assurance
Program Requirements (Operation)," Revision 2.
50
Ruhlman dep. at 59, 99.
51
Ruhlman dep., Exhibit 1034, Enclosure 8.
52
Haass dep., Exhibit 1088; Letter from H. Denton,
NRC, to Commissioner Kennedy, Subject: "Preventive
Maintenance," dated August 8,1979.
53 Qualifications of personnel who perform thesemaintenance and other activities are addressed in ANSI
N18.1-1971, "Training of Nuclear Power Plant Personnel,"and ANSI N45.2.6-1973, "Qualifications of Inspection,
Examination and Testing Personnel for the Construction
Phase of Nuclear Powerplants".
54
Memorandum from W. Ruhlman, NRC, to J. O'Reilly,"Recommendations for Changes in IE Programs," June29, 1979.
55
Haass dep. at 30; Gilray dep. at 53.
58
Eisenhut dep. at
80 (Pres. Com.); Ruhlman dep. at 35.
33

57

Haass dep., Exhibit 1089: Memorandum from W.
Haass, NRC, to W. Morrison, "QAB Comments on Proposed Regulatory Guide 1.XXX (RS-704-4)," July 24,
1979.
59

58
74
NRC, Regulatory Guide 1.26, "Quality Group ClassifiMemorandum from R. Tedesco, NRC, to G. Arlotto,
cations and Standards for Water-, Steam-, and"Request for Development of Regulatory Guide for ClassRadioactive-Waste-Containing Components of Nuclear
2-E Systems," May 20, 1977.
75
Powerplants,"
Revision 3.
Telephone Interview with Wilbur Morrison, Chief,
59
NRC, Regulatory Guide 1.29, "Seismic Design ClasEngineering Methodology Standards Branch, NRC Divisification,"
Revision 3.
sion of Engineering Standards.
60
78
Memorandum from F. Kruesi, NRC, to L. Rogers andGilray dep. at 94.
77
J. O'Leary, "Applicability of 10 CFR 50 Appendix B,"
Hanauer dep., Exhibit 1135, Memorandum from S.
August 15,1972.
Hanauer to Commissioner Gilinsky, "Technical Issues,"
e1
Haass dep. at 50; Gilray dep. at 51.
March 13, 1975.
82
78
Gilraydep.
at42.
Hanauer dep. at 50.
63
79
Haass dep. at 53, Exhibit 1090, Memorandum fromHaass dep. at 120.
80
H. Denton, NRC, to Commissioner Kennedy, "Quality"Technical Staff Analysis Report on Quality
Assurance Programs for Nuclear Powerplants," April 16,
Assurance," President's Commission on the Accident at1979. Before February 1979, staff practice by the review
Three Mile Island, October 1979, p. 17.
81
branches had not been to provide to the QAB a list of
NRC, "Generic Evaluation of Feedwater Transientssafety-related equipment originating in their areas ofand Small Break Loss-of-Coolant Accidents in Westingreview. Consequently, it is not clear whether the Q-lists
house Designed Operating Plants", NUREG-0611 (to bewere reviewed in detail. Haass dep. at 45.
published).
64
82Haass dep. atRoss dep. at 90.
54.
85
Examples of the practice are contained in 1) the83
NRC, Manual Chapter 3500, "(Quality Assurance,)"
Ross deposition, Exhibit 1156, Memorandum from D. Ross,
Enforcement and Inspection Manual, 8 volumes.
NRC, to D. Vassallo, "TMI-2 Input to SETC Supplement84
Telephone Interview with Eldon Brunner, Chief,
No. 2," February 6, 1978, and Exhibit 1157, Enclosure:
ReactorOperations and Nuclear Support Branch, NRC
Memorandum from D. Vassallo, NRC, to E. Christenbury,
RegionI
Office of Inspection and Enforcement; Ruhlman"Board Notification-Nonsafety-Grade Equipment to Miti34 and 53.
gate Transient (BN-79-12)," March 29, 1979; and 2) by dep. at85
Telephone Interview with Harold Thornburg, Director,
Issue I, "Treatment of Non-safety Grade Equipment in
NRC Division of Reactor Construction Inspection, IE.
Evaluations of Postulated Steamline Break Accidents in
88
U.S. Nuclear Regulatory Commission," Staff Discussion
Ruhlman dep. at 27.
87
of 15 Technical Issues Listed in Attachment to November
Kohler dep. at 65.
3, 1976 Memorandum for Director, NRR to NRR Staff,
88
Memorandum from B. Grier, NRC, to H. Thornburg,
NUREG-0318, November 1976.
66"Applicability of Appendix B to Safety-Related ConsumRoss dep., Exhibit 1157.
ables," October 5, 1977.
67
NRC, Information Report from E. Case to the ComBS
Memorandum from J. Sniezek, NRC, to B. Grier,missioners, Subject: "Single Failure Criterion, SECY-77"Applicability of Appendix B to Safety Related Consum439," dated August 17, 1977.
ables,"
December 8, 1977.
6B
90
Telephone Interview with Thomas Ippolitto.
Memorandum
from J. O'Reilly, NRC, to H. Thornburg,
89
Memorandum from H. Denton, NRC, to J. Ahearne,"Proposed Bulletin-Incorrect Positioning of Safety" Safety Implementation of Control Systems and Plant
Related Valves," March 21, 1975.
Dynamics," October 22,1979.
91
Memorandum from J. Crews, NRC, to H. Thornburg,
70
NRC, "Standard Review Plan for the Review of"Proposed Bulletin-Incorrect Positioning of SafetySafety Analysis Reports for Nuclear Powerplants-LWR
Related Valves," April 6, 1975.
92
Edition," NUREG-75/087, at Section 7.1.
NRC, "Reactor Safety Study-An Assessment of71
Telephone Interview with Rodney Satterfield, Chief,
Accident Risks in the U.S. Commercial Nuclear PowerI nstrumentation and Control Systems Branch, NRC, Diviplants," Executive Summary, WASH-1400 (NUREGsion of Systems Safety.
75/014), October 1975.
72
93
Memorandum from R. Tedesco, NRC, to G. Arlotto,
Memorandum from F. J. Nolan, NRC, to E. J.
"Request for Development of Regulatory Guide for Class
Brunner, "Baltimore Gas and Electric Company, Calvert
2E Systems," May 20, 1977; Memorandum from G.
Cliffs 1," December 8,1975.
Arlotto, NRC, to R. Tedesco, "Development of Regulatory
94
This program is described in Inspection and
Guide for Class 2E Systems," May 20,1977; Draft Paper
Enforcement Manual Chapter 2700, "Licensee Contractor
Submitted Informally to NRC, "Safety Classification ofand Vendor Inspection Program," Commission Information
Electrical Safety-Related Systems in Nuclear PowerLetter, "Licensee Contractor and Vendor Inspection Proplants," Combustion Engineering, 1974; Letter from R.
gram," SECY 77-64, February 2,1977; Commission InforSalvatorie, Westinghouse Electric Corporation to V.
mation Letter, "Letter to OMB Concerning NRC's LicenStello, Jr., Subject: Criteria for Safety-Related Electricalsee Contractor and Vendor Inspection Program," SECY
Equipment for Nuclear Power Generating Stations, West78-495, September 8, 1978; and "Report of a Study of
inghouse Electric Corporation NS-RS-279, July 3, 1974.
73
the Licensee Contractor and Vendor Inspection Program
Memorandum from R. Tedesco, NRC, to G. Arlotto,(LCVIP)", NUREG/CR-0217, July 1978.
"Comments and Ballot P-466, Criteria for the Design ofSafety-Related Surveillance Instrumentation (SRSI) in
Power Generating Stations," February 26, 1977.

NRC, Manual Chapter 2700, Enforcement andI nspection Manual, 8 volumes.
95

60NRC, "Licensee Contractor and Vendor Inspection
Status Report," NUREG-0400, Issued Quarterly.
97
Telephone Interview with Clifton Hale, Region IV
I nspector.
88
Mosley dep. at 190.
99
Skovholt Interview Memo (Sept. 27, 1979).
100
Haass dep. at 12.
1o1
Gilray dep. at 86.

NRC, "Task Action Plans for Generic Activities,"
November 1978.

98

117

118
NRC,
"Generic
Task
ProblemDescriptions:Category
B, C, and D Tasks," NURGEG 0471, June 1978.
119
Memorandum from E. Case, NRC, to Multiple
Addressees, "Summary of Technical Activities Steering
Committee Meetings 12 and 13, November 2 and 13,
1978," January 10,1979.
120

Summary Report on a Risk Based Categorization of
NRC Technical and Generic Issues, (DRAFT), Probability
Analysis Staff, 1978.
121
Hanauer dep. at 143.

102

NRC, "TMI-2 Lessons Learned Task Force Final
Report," NUREG-0585, at A-14, October 1975.
103 Letter from V. Stello, NRC, to Metropolitan Edison
Company, Subject: Investigation Report Number 50320/79-10, dated October 25,1979.
104
Memorandum from M. Aycock et al., NRC, to B.
Rusche, "Task Force Recommendations Related to theDevelopment of a Program Plan for the Management of
NRR
Technical Activities," March 15,1977.
105
Transcript of Public Meeting, "Discussion of SECY78-616-Reporting the Progress of Resolution of' Unresolved Safety Issues' in the NRC Annual Report,"
December 12, 1978.
108 Letter from M. Carbon, ACRC, to J. Hendrie, NRC,
Subject: Status of Generic Items Relating to Light-Water
Reactors: Report No. 7, dated March 21, 1979. Thisletter contains a relatively current list of resolved andunresolved generic issues which have been addressed by
the ACRS.
107Note from R. Heineman, NRC, to Multiple
Addresses, NRC, "Technical Safety Activities ReportDecember 1975," January 5, 1976.
108The categories established for these items were as
follows:
category A-Technical safety activities currently
receiving attention which have an important impact
on the licensing review process.
category B-Technical safety activities identified
as requiring NRR attention, but for which review
has not been initiated because of manpower limitations or because information is not available.
category C-Technical safety activities planned forthe future that would improve the quality of thereview or facilitate the review process.

122

Commissioner Action Request from H. Denton to
the Commission, "Reporting the Progress of Resolution of' Unresolved Safety Issues' in the NRC Annual Report,"
SECY-78-616, November 27, 1978.
123
Transcript of Public Meeting, "Discussion of SECY78-616-Reporting the Progress of Resolution of' Unresolved Safety Issues' in the NRC Annual Report," at128, December 12, 1978.
124

NRC, "Identification of Unresolved Safety Issues
Relating to Nuclear Power Plants," NUREG-0510, January
1979.
125
Memorandum from M. Aycock, NRC, to E. Case,"NRR Program for the Resolution of Generic IssuesPriorities and Future Actions," January 4, 1979.
126

Memorandum from H. Denton, NRC, to Multiple
Addressees,"Generic Issue Priorities," January 23,1979.
127
Transcript of Public Meeting, "Discussion of SECY78-616-Reporting the Progress of Resolution of'Unresolved Safety Issues' in the NRC Annual Report," at56, December 12, 1978.
128
Hearing Before the Joint Committee on Atomic
Energy, Congress of the United States, "Investigation ofCharges Relating to Nuclear Reactor Safety," Volumes 1
and 2 (February 18, 23, 24 and March 2, 4, 1976) at
1067-1068.
129Proceedings of the Atomic Safety and Licensing
Board in the Matter of Metropolitan Edison Company, etal., pp. 1316-1351, May 18,1977.
730
Atomic Safety and Licensing Appeal Board Decision
i n the Matter of Virginia Electric and Power Company, 8
NRC 245 (1978), August 25, 1978.
131
Atomic Safety and Licensing Appeal Board Decisionin the Matter of Gulf States Utilities Company, 6 NRC 760(1977), November 23,1977.

109

Hearings Before the Joint Committee on Atomic
Energy, Congress of the United States, "Investigation ofCharges Relating to Nuclear Reactor Safety," Volumes 1
and 2, (February 18, 23, 24 and March 2, 4, 1976) at
1065.
110
Id.at 97.
111
1d.
at
1052.
112
1d. at 494.
113
1d at 1494.
114
NRC, "Staff Discussion of 15 Technical Issues Listed
i n Attachment to November 3, 1976 Memo from Director,
NRR to NRR Staff," NUREG-0138, November 1976: NRC,
"Staff Discussion of Twelve Additional Technical Issues
Raised by Responses to November 3,1976 Memorandum
from Director, NRR to NRR Staff," NUREG-0153,
December
1976.
115
42 U.S.C. Sec. 5850.
118NRC Report to Congress, "NRC Program for the
Resolution of Generic Issues Related to Nuclear Power
Plants," NUREG-0410, January 1978.

132 Hearings Before the Committee on Government
Operations, United States Senate, "Nuclear Regulatory
Commission
SafetyandLicensingProcedures,"(December 13, 1976) at 1734.
133, at 1063.
13

Id. at 1066.

NRC, "Risk Assessment Review Group Report to
the U. S. Nuclear Regulatory Commission," NUREG/CR0400, September 1978.
1 35

Memorandum from S. J. Chilk to L. V. Gossick,"Staff Actions Regarding Risk Assessment Review Group
Report," January 18,1979.
136

137

Letter from C. Siess, ACRS, to J. Schlesinger, NRC,
Subject: Status of Generic Items Relating to Light Water
Reactors, dated December 18,1972.
61

ties" (Concerning Inerting of Containment Atmospheres
and Standards for Combustible Gas Control Systems),
SECY-78-290, June 1, 1978.
157
NRC, "Staff Discussion of Twelve Additional Technical Issues Raised by Responses to November 3, 1976
Memorandum from Director, NRR, to NRR Staff,"
NUREG-0153,
December 1976.
158
NRC, "Staff Report on the Environmental Qualification of Safety Related Electrical Equipment," NUREG0413,
February 1978.
159
NRC, "Environmental Qualification of Safety Related
Equipment at Nuclear Power Plants," IE Circular 78-08,
dated May 31,1978.
180
I nformation Report from E. Case to the Commissioners, "Single Failure Criterion," SECY-77-439, August
17,1977.
161
Memorandum from H. Denton, NRC, to Commissioner J. Ahearne, "Safety Implications of Central Systems
and Plant Dynamics," October 22,1979.
162
Atomic Energy Act of 1954, 42 U.S.C. Sec. 2232.
13
See, 10 C.F.R. Sec. 50.57(a)(4), "Issuance ofOperating License."
164
See, 10 C.F.R. Sec. 50.55(c), "Conditions of Construction
Permits."
165
10 C.F.R. Sec. 50.40(b).
1WSee, 10 C.F.R. Secs. 50.34(a)(9), (b)(7): "Contentsof Applications; Technical Information."
187
10 C.F.R. Sec. 50.34(b)(6)(i).
"Id. at (b)(6)(ii).
159
10 C.F.R. Sec. 50.36(c)(5).
170
NRC, "Standard Review Plan for the Review of
Safety Analysis Reports for Nuclear Powerplants-LWR
Edition,"
NUREG-75/087
171
The following sections of the Standard Review Plan
set forth criteria relevant to technical qualifications
assessments: Section 13.1.1, "Management and TechnicalSupport Organization"; Section 13.1.2, "Operating Organization"; and Section 13.1.3, "Qualifications of Nuclear Plant
Personnel."
172"American National Standard for Administrative
Controls for Nuclear Power Plants," ANSI N18.7-1972, at
Sections
3.3, 4.5, 5.1.
173
U.S. Atomic Energy Commission, "Utility Staffing
and Training for Nuclear Power," WASH-1130, at Section
June 1973.
IV-A,
174
NRC Regulatory Guide 1.8, Rev. 1-R, "Personnel
Selection
and Training."
175"American National Standard Requirement for
Selection and Training of Nuclear Power Plant Personnel,"
ANSI
N18.1-1971.
176
NRC, "Utility Staffing and Training for Nuclear
Power,"
WASH-1130, at Section IV-13,June 1973.
177
Vassallo dep. at 72.
178
Vassallo dep., Exhibit 1023.
179
AIlenspach dep. at 10.
180
1d. at 13.
181
Changes to the plant organization must be approvedby the NRC. Allenspach dep. at 39-40, 45 and 55.
182
Grier dep. at 30.
13
Allenspach dep. at 83; Haass dep. at 99.

1
NRC, "Staff Discussion of 15 Technical Issues Listedn
Attachment
to November 3, 1976 Memo from Director,iNRR, to NRR Staff," NUREG-0138, at Issue 4, November
1976.
139
Hearings Before the Committee on Government
Operations, United States Senate, "Nuclear Regulatory
Commission Safety and Licensing Procedures,"(December 13, 1976) at 260.
140
Memorandum from W. Butler, NRC, to D. Eisenhut,"Review of I&E Inspections of Operating PWRs Related to
the Follow-up Actions Identified in NUREG-0138 Issue No.
4, "Loss of Offsite Power Subsequent to Manual Safety
Reset Following a LOCA," December 29, 1977.
Injection
141
Memorandum from W. Butler, NRC, to D. Eisenhut,"Resolution of Certain Issues Concerning Loss of Offsite
Power Subsequent to Manual Safety Injection Signal
Reset Following a LOCA (NUREG-0138, Issue No. 4),"April
18,1978.
142
Memorandum from H. Denton, NRC, to R. DeYoung,"Request for Information dated June 27, 1979," July 13,
1977.
143
Hanauer dep., Exhibit 1035 (Memorandum, S.
Hanauer to Commissioner Gilinsky, "Technical Issues,"
March 13,1975).
"Hearings Before the Joint Committee on Atomic
Energy, Congress of the United States, "Investigation ofCharges Relating to Nuclear Reactor Safety," Volumes 1
and 2 (February 18, 23, 24 and March 2, 4, 1976) at 494.
145
Letter from D. Moeller, ACRS, to M. Rowden, NRC,
"Report on the Review of Statements by Messrs. Bridenbaugh,
Hubbard, Minor and Pollard," May 19, 1976.
146
NRC, "1978 Review and Evaluation of the Nuclear
Regulatory Commission Safety Research Program,"
Advisory Committee on Reactor Safeguards, NUREG0496,
December 1978.
147
Letter from M. Carbon, ACRS, to M. Rogovin,
TMI/SIG, "Response to Request for Information, dated
June 29,1979," dated July 25,1979.
148
Memorandum from H. Denton to Commissioner
Ahearne, "Instrumentation to Follow the Course of an
Accident,"
September 4,1979.
149
Transcript of Public Meeting, "Discussion of SECY78-616-Reporting the Progress of Resolution of' Unresolved Safety Issues' in the NRC Annual Report," at80,150December 12,1978.
Id . at 82.
151
Angelodep., Exhibit 1066.
152
Hanauerdep. at 75.
153
Hearings Before the Joint Committee on Atomic
Energy, Congress of the United States, "Investigation ofCharges Relating to Nuclear Reactor Safety," Volumes 1
and1542 (February--18, 23, 24 and March 2, 4,1976) at 1039.
Memorandum from J. Shapaker to R. Tedesco,
NRC, "Proposed Position on B&W Containment Isolation
System,"June 22,1976.
155
Letter from J. Herbein, Metropolitan Edison Company, to S. Varga, NRR, Subject: Meeting Minutes on
Feedwater Isolation Modifications to Meet License Condition156
C.(3).i, dated December 4,1978.
Consent Calendar Item from R. B. Minogue to theCommissioners, Amendments to 10 C.F.R. Part 50,"Domestic Licensing of Production and Utilization Facili-

62

.

Vassallo dep. at 73; Haass dep. at 73.
The licensing board considered the technical qualification of Boston Edison Company (Pilgrim 2).
97' Allenspach dep., Exhibits 1054 and 1064.
'Haass dep. at 74; Allenspach dep. at 23, 28.
*OVassallo dep. at 25.
20
OMemorandum from B. Rusche to NRR Division
Directors, NRC, Subject Revised Procedure for Documentation of Deviations from the Standard Review Plan,
dated January 31, 1977.
201
Allenspach dep. at 85.
202. at 86.

' 4 Allenspach dep. at

84.
'Allenspach dep. at 31, 62-65.
seVassallo dep. at 73, 78; H aass dep. at 81.
187
Allenspach dep. at 63; Exhibits 1057 and 1059.
'WHaass dep. at 81-82.
mAllenspach dep. at 85.
VOVassallo dep., Exhibit 1023.
*'Vassallo dep. at 71-73.
192

Allenspach dep. at'AIIenspach dep. at
194

Allenspach dep. at

17.
41; Haass dep. at
20.

72, 77.

63

B LICENSING AND
OPERATING HISTORIES
1. LICENSING HISTORY OF TMI-2

tion permit (CP) stage is described. We see in thissection that all concerns raised (some of which,such as small break analyses and emergency planning, would later become significant with respect to
the TMI-2 accident) were ultimately decided favorably by the regulatory bodies involved, and the construction permit was issued.
The postconstruction permit review period, some41/2 years in duration, is described in Section LB.1.d
and includes a summary of the licensing
organization's activities. Since the Atomic Energy
Commission (AEC) licensing staff's interaction with
the TMI-2 project was only intermittent during theseyears, and important regulatory events were
reshaping the review process, some of these events
are briefly mentioned. In addition, some of the difficulties inherent in the conduct of the postconstruction permit licensing review are discussed.
The operating license review period is presented
i n Section I.B.1.e. During this time the Atomic
Energy Commission was abolished and the regulatory staff was restructured into the Nuclear Regulatory Commission. A later expansion of the licensing
staff was designed in part to incorporate the feedback of operating experience into new or modified
li censing requirements.
An overall operating license review summarystresses the role of the ACRS and the Atomic Safety and Licensing Board. The operating license is-a. Introduction
This portion of the Special Inquiry Group Reporti s a summary analysis of the licensing history of theTMI-2 project. A background description of the regulatory institution in which the licensing reviews
took place is included in order to provide additional
i nsights into the events that did or did not occur.
Following this introduction, an initial summary, reviews the overall chronology of the licensing of both
TMI-1 and TMI-2, which are nearly identical plants
and adjacent to one another on the same island in
the Susquehanna River.
Section I.B.1.c presents a summary of the TMI-2
construction permit review, set against a historicalbackground description of the structure of theli censing staff and the evolution of the licensing process up to that time. The construction permit review was completed in approximately 1'/z years
during a period of rapid expansion of the nuclear industry and the agencies designed to regulate it.
Safety criteria have only been partially developed
and are still evolving. Staff and the Advisory Committee on Reactor Safeguards reviews are also
described in this section and several of the issues
covered in those reviews are discussed. In addition,
the TMI-2 public hearing process at the construc-65

commercial power reactor licensed to operate wasIndian Point 1, which could produce only about onefourth the thermal power of the 177 fuel assembly
design and was a considerably different reactor
system design.
After the AEC staff review and a public hearing
before an ASLB in April 1968, the Commission issued a provisional construction permit for TMI-1 on
May 18, 1968. In March 1970, Met Ed filed a Final
Safety Analysis Report as a prerequisite to obtainan operating license for TMI-1. Following staff review and a public hearing lasting 3 days in November 1973, an operating license was issued for
TMI-1 in April 1974.
I n April 1968, JCPL submitted an application for anuclear plant to be located adjacent to the existing
Oyster Creek 1 in Ocean County, New Jersey. In
March 1969, JCPL and Met Ed, as co-owners of thisplant, jointly submitted an amendment to that application indicating a site change to the site where
TMI-1 was under construction. In 'January 1971, thePennsylvania Electric Company was added as aco-owner of the facility. It and JCPL each owned
25% of the facility and Met Ed owned the remaining
50%. The proposed plant was designated TMI-2
and was to be located adjacent to TMI-1. This plant
was very similar to the TMI-1 plant, in using a B&W
nuclear steam supply system essentially identical tothat already under construction for the TMI-1 unit.
The AEC reported the results of its review of theTMI-2 construction permit application in a Safety
Evaluation Report dated September 5, 1969. Following a public hearing, Provisional Construction
Permit No. CPPR-66 was issued for TMI-2 on November 4,1969.
The applicant docketed the FSAR for TMI-2 onApril 4, 1974. The NRC, newly created by the Energy Reorganization Act of 1974, assumed the regulatory functions and personnel of the AEC and became functional in January 1975. Staff review
resulted in a September 1976 release by NRC of a
Safety Evaluation Report related to the operation of
TMI-2.
At the time the Safety Evaluation Report was
released several issues remained to be resolved. In
September and October 1976, the NRC staff andthe applicant met with the ACRS to review the application, and the ACRS issued a letter report to theCommission on October 22,1976. The Commission
staff issued two supplements to the Safety Evaluation Report in March 1977 and February 1978, indicating the resolution of all matters pertinent toli censing the plant to operate.
Petitions to intervene in the operating license review which began in April 1974 were received, andsued for TMI-2 is discussed to show that it contained a large number of safety-related work items
that had to be completed and approved by the NRC
prior to becoming an effective full power license.
This is not unusual in NRC practice, and does not,of itself, imply that important safety issues are
avoided by the issuance of a license. But the issuance of a license does realign work priorities
within the NRR and leads to some diffusion of theclear lines of project management responsibility andauthority extant prior to issuance of a license.
The final portion of Section I.B.1.e examines the
conduct of the review with respect to several safetyissues of significance to the TMI-2 accident. The
issues discussed generally show how Met Ed met
the staff's requirements at the time of the review.
However, these requirements or the procedures toensure compliance with them were inadequate toguarantee that the TMI-2 accident would not occur.
Section I.B.1.f concludes this historical overview
with findings and recommendations presenting
some points that do not necessarily correspond to
specific parts of the preceding sections. The points
are the product of both this particular phase of the
SIG's investigation and of the consultation withmany people who participated and assisted in thisi nquiry.
b. Summary of Licensing Events-TMI-2 andTMI-1

I n May 1967, Met Ed applied to the AEC for ali cense to construct and operate the first unit, TMI-1,
at a site on Three Mile Island in the SusquehannaRiver, about 10 miles southeast of Harrisburg, Pa.
TMI-1 is jointly owned by Met Ed, the Jersey Central
Power and Light Company (JCPL), and the Pennsylvania Electric Company, which are named as licensees.
The plant was to use a 177 fuel assembly Babcock and Wilcox (B&W) nuclear steam supply system (NSSS) identical to those proposed by DukePower Company in their December 1966 application
to construct the Oconee 1 and 2 reactor plants.
Three other applications docketed in 1967 proposed
to use the same B&W NSSS.
An unexpected spate of reactor plant applications were submitted to the AEC in 1966 and 1967,as 30 additional new applications were docketedthan the total for the previous 12 years. A tableshowing some data for plants that have been
licensed to use B&W reactors is shown in Appendix
1. 3. As this table indicates, prior to the series ofreactors typical of the TMI design, the only B&W
66

the Commonwealth of Pennsylvania requested toparticipate as an interested State. In July 1974, the
ASLB designated to rule on intervention requests
granted the Commonwealth's request as well as thej oint intervention request of two local environmental
interest groups. This set the stage for a public
hearing on the operating license application, aproceeding not required at the operating license
stage absent intervention.
The hearing on reactor safety issues conductedduring 1977 resulted in an initial decision on December 19, 1977, that authorized the director of Nuclear Regulation:

Then, as now, the project branch was responsible
for managing and coordinating the staff review,preparing and issuing the staff's Safety Evaluation
Report, and for representing the staff before both
the ACRS and the ASLB. At that time, however,more of the technical review was conducted by the
project manager and his associates. Specialist
branches in DRS were used when necessary toprovide a depth of expertise not available in the project management organization.
Because the review process was not as formallystructured as it is today, more of the technical review responsibility could be retained within the project management group, and usually was. Both thescope and depth of the review were more limited
than the reviews conducted today, however. As aresult, reviews were completed within a year byfewer staff members than participate in more recent
reviews. The technical assistance obtained during
the review from DRS, as well as from within DRL,
was from assistant directorates for reactor technology and reactor operations, groups parallel to theassistant directorate comprising the reactor projects branches.
During this same period, the regulatory philosophy was undergoing changes. Up to 1966, the AEC
premised its regulatory requirements on an approach to safety that focused on the provision of astrong steel containment around the reactor and apolicy of remote location away from populatedareas. The Commission's strategy was to confine
the consequences of a postulated maximum credible accident rather than to guarantee prevention ofthat accident.
The safety philosophy wasdeveloped during the early years of commercial
power reactors when 100 MW electric plants weretypical. By 1966, only six commercial nuclear electric plants were in operation, all at 265 MW or less.
By 1967, however, reactor plants were being
designed to produce 800 to 1000 MW, thereby
greatly increasing the potential consequences of aserious accident.
A commonly accepted definition of risk is an expected loss, quantitatively expressed as the probability of a postulated accident times the consequences of that accident. The risk of a serious accident was certainly increasing rapidly, if considered
only from this viewpoint. Simple containment of thelarger amounts of energy and stored radioactivity
that could be released from the larger reactor
designs was becoming more difficult to guarantee
by analysis. Designs began to include additional
backup systems, such as the emergency core cooli ng system, to mitigate the consequences of large
loss-of-coolant-accidents.

mo continue in effect the construction permit of. . ., and to make such additional findings on uncontested issues as may be necessary to the issuanceof a full-term operating license for that unit consistent with the terms of this Initial Decision'

Following the resolution of several outstanding safety matters, the NRR issued Facility Operating
License No. DPR-73 for TMI-2 on February 8, 1978.
Simultaneously, Supplement No. 2 to the Safety
Evaluation Report was issued documenting theresolution of all identified safety issues. As withother operating licenses issued at that time, resolution in some cases required plant operational limitalions, which were included as conditions in theli cense calling for certain preoperational tests, startup tests, and other items. Some conditions required
further NRC approval before progressing throughvarious operational modes needed to reach fullpower.
c. TMI-2 Construction Permit Review-May
1968 to November 1969
Historical BackgroundAt the time of docketing and during the subsequent construction permit review for TMI-2, the regulatory staff structure was facing an unprecedented expansion of the commercial utilization of nuclear
power. Between 1962 and 1966, the AEC received
construction permit applications for 26 reactor units,
15 of which were submitted in 1966. 2 I n 1967, 18
new applications were docketed, and in 1968, 10
more followed. At that time, the entire staff review
of an application to construct and operate a nuclear
powerplant was conducted within two groups
known as the Division of Reactor Licensing (DRL)and the Division of Reactor Standards (DRS) (seethe organization chart in Figure I-1). An application
was assigned to a licensing project manager in oneof the several reactor project branches in DRL.
67

FIGURE I-1. Organization Conducting Licensing Reviews in October 1968

The report of a task force headed by William Ergen of the Oak Ridge National Laboratory issued inlate 1967 moved the AEC toward a safety philosophy that demanded increased consideration of accident prevention as well as mitigation. However,this changed philosophy led to a considerably more
complex set of regulatory requirements, including avariety of design and procedural features such as
quality assurance, redundancy, more sophisticatedemergency core cooling systems (ECCS), and otherengineered safety features. In September 1971, thedirector of Regulation explained:

ty. Judgment is rendered on an inadequate basis,and therefore is subject to change as additional
knowledge is gained. 3

The same situation exists in 1979. Thus, during
1967 and in the years following, regulatory acceptance criteria for many basic licensing issues were
continually evolving. The inevitable result was thatan applicant for a powerplant found that different
criteria had been applied to proposed designs thanwere applied earlier to evaluate similar designs. Thei ndustry quickly dubbed this approach "ratcheting",
a continual stepwise increase in the number and sophistication of design features required by the regul atory staff to meet the same basic criteria expressed in the AEC's General Design Criteria.
Staff review requirements under development in
the 1968-1969 period included: 4

The principal defense against accidents is prevention. All structures, systems, and components important to safety must be designed, built, andoperated so that the probability of occurrence of an
accident is very small. The key to achievement of
this objective is an effective quality assurance program.... However excellent the quality assurance
program, it must be acknowledged to be imperfect.
Protective systems are installed therefore to deal
with such transients and failures as may occur
despite all that is done to prevent them. A third
echelon of the defense in depth is the engineered
safety features designed to cope with unlikely
failures that go beyond the capabilities of the accident prevention and protection systems, as wellas highly unlikely failures of the other defenses
themselves. The designs of engineered safety
features are evaluated to provide assurance thatthey will function properly under accident conditions. Each line of defense must be well designed
and executed for effective implementation of the
defense-in-depth concept. For example, system
performance is evaluated assuming a failure of any
single active component in any engineered safety
feature.

••••Tornado design criteria
Structural criteria for nuclear vessels
Seismic design criteria for structures
Emergency core cooling system evaluation
guidelines• Flood design criteria• Fission product formation and removal evaluation• Models for calculating atmospheric diffusion ofradioactive releases• Assumptions used for calculation of accident
consequences• Design of structural steel embedments in concrete containment structures• Design basis for pressurized-water reactor (PWR)"dry" containments• Design basis for fuel failure and rod worth calculations, and• Guidelines for steam line break evaluations.

The shift to this defense-in-depth policy resulted
i n a regulatory process that continually identifies
new, additional design basis events that are oflesser consequences than a maximum credible accident, but have a higher probability of occurrence.
The lack of a clear mandate on the level of acceptable risk, or the analytical tools and reactor operati ng data to establish the probability component ofrisk, considerably magnified the regulator's problems in pursuing the defense-in-depth concept,
however:

These technical issues were addressed in reacfor technology memoranda (RTM), which represented an effort to systematize the review process bydefining uniform requirements for use by all technical personnel on the review staff. However, as amatter of practice, the RTM were put into use before they were finally approved, resulting in the implementation by reviewers of requirements thatwere still changing with time. This was the classic
development of "ratcheting." Statements from cover memos transmitting the new RTM for use makethe point:

In principle, defense-in-depth can be proliferated
endlessly, analogous to the possible proliferation ofdesign basis accidents. Diminishing returns fromsuch proliferation dictate establishment of a limit to
the required defense-in-depth, again analogous to
the distinction between 'credible' (Class 3) and 'incredible' (Class 4) events. This limit, expressed aseither a requirement for depth of defense or an array of credible events for which protection is required, is one of the most difficult technical safetyissues to resolve. As usual, the lack of knowledge
regarding probabilities is responsible for the difficul-

The attached first draft of an RTM on off-site electric power is submitted for comments from Reactor
Technology. We will informally test the positions
proposed in the draft in our next severalcase evaluations. The results of trial usage and RT
comments will be factored into the second draft. 5(Emphasis added.)70Furthermore:which the ACRS would review with applicant andstaff the application for a construction permit. An
internal staff memorandum to Peter Morris, thenDirector of the Division of Reactor Licensing, statedthat resolution of the remaining matters could be
deferred until after the issuance of the construction
permit because, "[t]hey are either (1) items of a general nature generic to this class of reactor plant or(2) additional information not yet available is necessary to resolve these matters on a quantitative
9basis." The matters highlighted in this memorandum included ECCS signal diversity, the applicant's
commitments concerning control of hydrogen concentration in containment, and a staff requirementthat the applicant submit plans for inservice inspection within approximately 6 months of construction
permit issuance. Following an initial meeting with an
ACRS subcommittee on June 26, 1969, the subcommittee members indicated additional mattersthat they felt might be addressed at the committee
meeting scheduled for July 10, 1969. Among thesewere the site emergency plan and the instrumentation that would be supplied to assure that ECCS
operation could be monitored following an accident to
At the ACRS meeting on July 10, 1969, the committee discussed the application with representatives and consultants of both JCPL and Met Ed,
General Public Utilities Corporation (GPU), B&W,
Burns and Roe, Inc., and the AEC regulatory staff.
Following this meeting, the ACRS reported to the
AEC chairman that it believed that, if due considerabon was given to certain concerns, the TMI-2 plant
could be constructed with reasonable assurance sothat it could be operated without undue risk to thehealth and safety of the public." The committee's
l etter reiterated several, but not all, of the concerns
i dentified elsewhere in the report of this inquiry, but
i n each case found that the matter could be
resolved during construction of the plant.
Staff concerns which became committee concems included the applicant's plans to cope withpotential hydrogen concentration in the containment, and questions regarding instrumentation connections designed to preserve the independence ofprotection and control systems. The committee
also expressed concern about the integrity of the
postaccident cooling system throughout the courseof an accident. The focus of its concern was not on
the specification of ECCS performance requirements as a function of the type of break, however,
but rather that the ECCS would function for extended time in the accident environment. Significantly,
the ACRS also called for a study of the possible
consequences of hypothesized failures of protective

The enclosed document sets forth design criteria
for PWR dry containments. These criteria weredeveloped by a DRS-DRL team. The Director,
DRS, concurs with the criteria. The Director, DRL,
has directed that the criteria be used by DRL on a
trial basis ' across the board.' Copies of the criteria
will be distributed to all division technicalpersonnel for this purpose. 6

The Construction Permit Review

The construction permit review of the TMI-2 application was assigned in early 1968 to Licensing
Project Leader Ray Powell, a member of Reactor
Projects Branch No. 2. Powell's branch chief wasRobert Tedesco. An initial plan for the review wasapproved and implemented in June 1968 (Figure I2). A chronological summary of the construction
permit review as actually conducted was included in
the September 1969 Safety Evaluation Report by
the staff and is reproduced in Figure 1-3.
During the staff's construction permit review,
written requests for information were sent to the applicant on three occasions in 1968. The staff met
with applicants' representatives 12 times during
1968 and 1969, prior to an ACRS subcommittee's
consideration of the application on June 26, 1969
and the committee's consideration on July 10,
1969.
The October 18, 1968 staff requests for information included a request for a description of ECCS
performance for postulated piping breaks of lessthan 0.4 square feet in area. The applicant had proposed that the ECCS be initiated by a low reactor
coolant pressure (1800 psig) or alternatively by highcontainment pressure (4 psig). The staff was concerned, however, that for some small breaks thesystem's response might be delayed by a slower
reactor depressurization. The applicant provided
the results of analyses to demonstrate that the containment high pressure signal for the emergency
core cooling system's initiation provided adequate
backup protection for postulated reactor coolant
pipe rupture areas down to 0.022 square feet. Thisi s still larger than an open pressurizer relief valve,
which is about 0.007 square feet. The staff later
concluded that the applicant's design was acceptable.
By June 20, 1969, both the staff review and theapplicant's responses were considered adequate tosupport an evaluation report addressed to the
ACRS. 8 This type of report was the current licensi ng practice and constituted a summary of thestaff's review; this report, written exclusively for the
ACRS, had been prepared prior to the meeting in71

0 ateApplication and PSAR filed

April 29, 1968

Meeting to establish review plan

May 28, 1968

Issue Division of Reactor Licensing review plan

June 5, 1968

Preliminary report to ACRS submitted

May 29, 1968

First meeting with applicant and designer

June 11, 1968

ACRS briefing and technical meeting for grouted
tendons presentation by applicant

June 13, 1968

Draft of Reactor Technology and consultant's

July 29, 1968

Reactor Technology and Reactor Operations

July 29, 1968

Division of Reactor Licensing questions toapplicant submitted

August 9, 1968

Applicant's response to Division of Reactor
Licensing questions

August 30, 1968

Consultant reports (drafts) received

August 30, 1968

Technical meeting to settle problem areas
resulting from consultants' reviews

September 1968

Final consultant reports received

September 20, 1968

ACRS Subcommittee meeting at site

October 1968

Reactor Technology and Reactor Operations
ACRS report sections due

November 1, 1968

ACRS report to ACRS

December 20, 1968

ACRS meetings

January 2 & 3, 1969

Completion of Safety Evaluation

January 1969

Pre-Hearing

January 1969

Hearing

February 1969

Issuance of construction permit

February 1969

questionsquestions due*

MEMORANDUM, PETER MORRIS, DIRECTOR, DIVISION OF REACTOR LICENSING,TO MULTIPLE ADDRESSEES, "REVIEW PROGRAM AND ASSIGNMENTS FOR OYSTERCREEK UNIT NO. 2, DOCKET NO. 50-320," JUNE 10, 1968.

FIGURE 1-2. Schedule for Oyster Creek Unit 2 (Docket No. 50-320)*72

April 29,1968
Application filed with three volumes

Preliminary Safety Analysis Report (PSAR) for
Oyster Creek Site

May 24,1968
Amendment No. 1 filed (clarification of

Oyster Creek Unit 2 core power level and net
electrical output)

June 11, 1968
I nitial meeting with applicant (Jersey Central

Power & Light Company) to review design

June 13, 1968
Meeting with staff and ACRS to review grouted
tendon test program

July 1, 1968
Amendment No. 2 filed (grouted tendon test
program)August 16,1968
Meeting with applicant to review site and design
criteria

August 27, 1968
Meeting with applicant to discuss seismic criteria,
grouted tendons, liner design, instrumentationand quality assurance program

September 3, 1968
Amendment No. 3 filed (response to staff's
request concerning reanalysis of probablemaximum hurricane flood height)

FIGURE 1-3. TMI-2 Chronology of Review. Taken from safety evaluation by theDivision of Reactor Licensing, U.S. Atomic Energy Commission, in the matter ofMetropolitan Edison Company and Jersey Central Power and Light Company, Three

Mile Island Nuclear Station Unit 2, Dauphin County, Pa. Docket No. 50-320,
September 5, 196973

November 4,1968
Amendment No. 4 filed (response to staff's
request for additional information dated
September 19,1968)
November 8, 1968
Grouted tendon tests performed by Stressteel
Corporation for applicant (witnessed by staff)
November 29,1968
Amendment No. 5 filed (response to staff's
i nformation request dated October 18, 1968)
December 10, 1968

Meeting with applicant to discuss iodine
removal capability

January 15, 1969
Meeting with applicant to discuss change ofplant site from Oyster Creek to Three Mile
Island site and effects of change on plant design
February 14, 1969
Meeting with applicant to discuss grouted tendon
surveillance program and quality assurance program
March 10, 1969
Amendment No. 6 filed (response to staff's requestof October 18, 1968 plus complete PSAR revisionchanging plant site to Three Mile Island site)
March 17,1969
Amendment No. 7 filed (response to several
matters raised in meetings with the applicant)April 16,1969
Amendment No. 8 filed (revision and additional
i nformation regarding diesel load and size andcontainment pressure test)

FIGURE I-3-Continued

74

May 1, 1969

May 7,1969

May 13,1969

May 22,1969

June 16,1969

June 26, 1969

June 27, 1969

July 9,1969

July 10,1969

July 17,1969

Applicant's request for exemption to permit
construction of tendon access gallery
submitted

Amendment No. 9 filed (change of responsibility
for design and construction to Metropolitan
Edison Company)

Meeting with applicant to discuss instrumentationand controls circuits

Supplemental information relating to public
need for exemption request submitted

Meeting with applicants to discuss flood protection
requirements

ACRS Subcommittee meeting with staff andapplicantRequest for exemption to construct tendon
access gallery granted

Meeting with applicants to review applicant's
design margins for grouted tendon prestresssystemReview by ACRSACRS letter to Chairman Seeborg on Three Mile
Island Nuclear Generating Unit No. 2
FIGURE 1-3-Continued
75

systems during anticipated transients, including
steps required to limit the consequences. The
staff's formal and publicly available Safety Evaluation Report of September 5, 1969, 12 i ssued several
months after the committee meeting, included both
the ACRS letter to the AEC and a summary of thestaff and applicant plans to comply with thecommittee's recommendations during constructionof the plant and during the operating license reviewof the plant.
In addition to design and analytical technical issues, the staff review at the construction permit
stage included consideration of the applicants'
technical qualifications to design and build TMI-2,
the proposed Quality Assurance Program, and theapplicant's plans for the conduct of operations at
TMI-2. These matters also were reported in thestaff's Safety Evaluation Report. The staff's findingthat the applicant was technically qualified wasbased on an evaluation of information supplied by
the applicant. The co-owners of the proposed
plant, Met Ed and JCPL, had described how they
were owned by GPU, a holding company that
owned two additional utility companies. GPU also
owned and operated the Saxton Research and Experimental Nuclear Unit. GPU had formed a Nuclear
Power Activities Group to provide direct technicalassistance to the nuclear project managers of its
subsidiary companies. The TMI-2 project director
for Met Ed was the vice president and chief engineer in the Met Ed Company. In addition, at thatti me a boiling water nuclear powerplant owned by
JCPL, Oyster Creek Unit 1, was nearing operational
status, and the TMI-1 plant, also owned by Met Ed,
status, then under construction. The key participants
i nvolved in the TMI-2 project during 1969 are listed
in Table 1-5.
Staff evaluation of the applicant's quality assurance plans was based on Met Ed's description of
its commitments to certain actions and organizational structure. These Met Ed plans were measured
against the staff's proposed Amendment to 10
C.F.R. 50, Appendix B, concerning quality assurance requirements, dated April 17, 1969, andfound acceptable. The applicants' preliminary plansregarding plant operations were examined in theareas of personnel training, administrative controls,
review and audit of operations, and the emergency
plan. The staff's finding that these plans were adequate at the construction permit stage was basedon the similarity of these plans to those for TMI-1
that had been found to be acceptable at the construction permit stage approximately 1 year earlier.
Following the Safety Evaluation Report issuance,a public hearing was held in Middletown, Pennsyl-

vania, on October 6, 1969. No petitions for leave tointervene were filed with the ASLB and the only parties to the proceeding were the applicant and thestaff. The staff, over the signature of the director of
regulation, had already published both its proposed
findings in the case and a proposed provisional construction permit with the Notice of Hearing in theFederal Register. 13
I n accordance with theCommission's rules of practice, the board was toconsider whether the application and the record of
the proceeding contained sufficient information, andwhether the staff's review had been adequate tosupport the proposed findings and the proposed
provisional construction permit. An area resident
presented a limited appearance statement expressi ng concern relating to protection of the facility fromaircraft using the nearby Olmstead State Airport.
Thomas M. Gerusky, a representative of thePennsylvania Department of Health, stated that mutually satisfactory programs relating to radiologicalhealth and emergency procedures had been established in cooperation with the applicants and the
U.S. Public Health Service.
On October 31, 1969, the ASLB issued its initialdecision on the matter of TMI-2. The board foundthat the staff's review had been adequate to support
both the proposed findings and the proposed provisional construction permit (see also the summary of
adjudicatory proceedings in this report). Relevant
findings of fact in the hearing, paraphrased from theinitial decision (see Appendix 1.7), were as follows:• The applicants and staff had identified specific is-sues warranting research and development efforts necessary to develop the final design of the
facility. The areas of research and' developmenti ncluded analyses or tests on core thermal andhydraulic design, fuel-rod clad failure, internalvent valves, once-through steam generator,
blowdown forces on reactor intervals, chemical
spray system, and the effects of radiolysis. A
schedule for furnishing information prior to completion of construction of the proposed facility
was established by the parties to the hearing.
• The applicants had established a comprehensive
Quality Assurance Program consistent with thei ntent of the AEC's proposed Appendix B to 10
C.F.R. Part 50.

The ASLB thus instructed the director of regulation to issue a provisional construction permit to
JCPL and Met Ed. On November 4, 1969, Provisional Construction Permit No. CPPR-66 was issued. The Atomic Safety and Licensing Appeal
Board examined the record of the proceeding andaffirmed the decision of the ASLB in a memorandum
76

TABLE 1-5. TMI-2 projects organization
Organization

Function

Burns & Roe, Inc.

Architect-engineer

United Engineers & Constructors

Construction Manager

Co-owners

Metropolitan Edison Company
Jersey Central Power & Light
Company
Metropolitan Edison Company

Responsible for design, construction,and operation
Design consultant

Pickard & Lowe Associates

Nuclear steam supplier

Babcock & Wilcox
MPR Associates

Provide quality assurance assistanceTechnical assistance

GPU Nuclear Power Activities
Group

Structural consultant

Schupack & Associates

Architect-engineer, cooling towers andswitchyard and aircraft design
consultants

Gilbert Associates, Inc.

Act (NEPA) of 1969 and the Water Quality Improvement Act. This environmental legislation resulted inadditional demands on both the users and the regul ators of nuclear power. While the new environmental issues of thermal pollution and low level radiation
effects did not directly influence radiological safety
reviews, the additional scope of staff effort required
for a given application to construct a plant presented increased management challenges to the regulatory agency.
I n May 1971, the AEC reported the results of a reduced scale test of an emergency core cooling system conducted at its Idaho test facility. Although
the test apparatus differed from a real ECCS in important ways, the test results unexpectedly cast
doubt on the efficacy of such systems, and within amonth the AEC issued emergency Interim Acceptance Criteria to assure safe operation of the ECCS
if called upon. The adequacy of the ECCS immediately became an issue in construction permit andoperating license hearings generally, and in the
TMI-2 system in particular.
Met Ed was requested by a letter dated August
13, 1971 to provide information to show that the
ECCS proposed for TMI-2 would meet the AEC criteria using a suitable evaluation model. The model
was to be developed by Babcock and Wilcox, worki ng directly with the AEC. The letter asked that thei nformation be submitted with an application for anissued November 25, 1969. The Commission took
no further action, and the construction permit decision became the final and official Commission action
effective December 11, 1969.
d. The Postconstruction Permit Review
Period, 1969-74
Met Ed encountered delays in the construction of
TMI-2 (discussed later in this section) and did not
submit its application for an operating license until
February 1974. In the several years following the issuance of the construction permit in November
1969, the regulatory process continued to grow in
the number and complexity of safety matters whichwere of concern to the regulatory staff. (The licensing organization during this period is described inAppendix 1.4.)
Following the 1969 construction permit issuance
for TMI-2, reactor designs continued to evolve, as
the number of reactor plant applications increased
rapidly, continuously outpacing the staff's ability tocollect, evaluate, and utilize plant operating experience in the licensing process. (As noted in Appendix 1. 4, an Office of Operations Evaluation was established for this purpose in April 1972.) Protection of
the environment emerged as a dominant national issue, culminating in the National Environmental Policy
77

operating license, which at that time was not anticipated for at least another year. Met Ed was advised that if they submitted the material earlier, "wewill review it in accordance with the priorities thatexist at that time..."However, the TMI-1 project was under operating
license review at this time (since March 1970) andthe TMI-1 design incorporated the same B&W nuclear steam supply system. Met Ed addressed the
ECCS interim acceptance criteria on the TMI-1 application, where their submittal was reviewed andreported in the staff's Safety Evaluation Report issued for TMI-1 on July 11, 1973. This report covered
the consequences of postulated small breaks in thereactor coolant system, and found that the ECCS
would provide adequate protection for small breaks
i n the reactor coolant system. The smallest breakexamined in the evaluation was a 0.04-square footbreak in the reactor coolant pump suction piping,larger than an open pressurizer relief valve, which
would be an approximately 0.007-square foot orifice. The work done on the TMI-1 project was later
confirmed in the TMI-2 operating license review.
On July 15, 1970, the director, Division of Reactor
Licensing, notified Met Ed that the AEC would require, at the time of filing the Final Safety Analysis
Report, information to support the staffs preparalion of an environmental impact statement for the
TMI site. The information required was outlined in
the letter. In a subsequent letter to Met Ed dated
September 3, 1971, the director of regulation advised that in the Calvert Cliffs decision of July 23,
1971, the U.S. Court of Appeals for the District ofColumbia had required a revision in the AEC's policy
for implementing NEPA, and enclosed the effective"interim" policy. The environmental review was, inaccordance with staff practice, conducted independently of the radiological safety review, which wasat this point essentially quiescent for the TMI-2 project. In December 1972, the AEC staff issued a Final Environmental Statement reflecting the completion of the environmental review for both TMI-1 andTMI-2.
Also during this period, the groundwork was bei ng laid for issuance of improved regulatory staff
guidance to applicants regarding the criteria for radiological safety reviews. As a result of the regulatory staff reorganization of March 1970, the internalguidance termed reactor technology memoranda
became publicly available as safety guides
developed by the Division of Reactor Standards. As
Harold Price, the Director of Regulation, explained to
the AEC Commissioners in a memo concerning thei ssuance of safety guides:
There is a need for an expeditious means of providing additional guidance to applicants on the ac-

ceptability of proposed design features... We believe such safety guides have the potential for
reducing the present uncertainties in the licensing
process and also have the potential for reducing
regulatory staff and ACRS workload on individual
cases since less review of individual designs will be
required 14
The memo proposed issuance of the first threeguides, and listed several others that the staff wasworking on.
In June 1970, there were no approved AEC General Design Criteria as part of the regulations,although a set of such criteria had been proposed
for inclusion in 10 C.F.R. 50 in July 1967. Prior to issuance of the GDC, the purpose of the new Safety
Guides was, as expressed in an Appendix to thePrice memo to the Commissioners in June 1970, to" make available to the industry solutions that are
acceptable to the regulatory staff and the Advisory
Committee on Reactor Safeguards on certain safetyissues." Safety guides continued to be developed(they later became regulatory guides) and became
one of the several instruments used to express thetechnical review staff's interpretation of the GDC.
The GDC were finally issued as Appendix A to 10
C.F.R. 50 in February 1971. The criteria, althoughgeneralized statements, clearly represented theessence of staff past practice and focused onmatters of principal safety significance that had
evolved through regulatory actions since the mid1960s.
With the exception of the new ECCS requirements and the new NEPA requirements, both ofwhich were issued to Met Ed with instructions to
consider no later than the time of application for an
operating license, no items having later significanceto the TMI-2 accident arose through 1971.
Construction continued for both units at Three
Mile Island, and in March 1972, GPU met with thestaff to inform them that the operating license application for TMI-2 would be submitted in Septemberor October 1972, and that plant construction was
about 25% complete, with fuel loading scheduled forearly 1975.
Two separate events in 1972 led to the identitication and the regulatory staff's articulation of specificsafety design criteria that were not identified prior tothat time. First, a leak in a large nonsafety-related
expansion joint at the Quad Cities plant in Iowa
resulted in water damage to equipment that would
be important in safe plant shutdown. Accordingly,
Met Ed and other applicants were informed in September of the necessity to consider the potential fordamage to safety equipment by failures of nonsafety
equipment.
The second event was an anonymous letter tothe ACRS raising questions about the safety of cer78

tain pipe locations at the Prairie Island plant in Minnesota. The writer was concerned that ruptures inmain steam or feedwater lines, outside of the containment, could damage adjacent equipment or
structures necessary to mitigate the consequencesof the pipe rupture. The ACRS brought the matterto the attention of the staff, which, after reviewing
the Prairie Island design, decided that changes werenecessary and that all plants should be examined toensure that adequate protection was provided. Met
Ed was notified in December that a response would
be required.
I n August 1973, Met Ed was informed that achange in the regulations governing operator licensi ng would require inclusion of a description andplans for implementation of an operator requalification program in the operating license application.
Prior to 1973, licensed operators were required torenew their licenses every 2 years, but could obtainrenewal simply by showing that they had performed
the duties for which they were licensed and that
their current employer had continuing need of theirservices as licensed operators. No retraining or requalification had been necessary. The requalification requirements embodied in the regulations effecfive on September 17, 1973, 38 Fed. Reg. 22221(1973), are presently still in effect.
The three issues described above were presented to Met Ed (at different times) with the requestthat a response be provided within 30 days, without
regard to when Met Ed might submit their operating
license application. This staff practice was typicalof that time and is also used today. Selected "generic" issues identified by the staff and consideredsufficiently important to warrant immediate notification of each applicant by letter are to be responded
to promptly by the 'applicant even if outside the context of an ongoing construction permit or operating
license review. The applicant's response to thestaff request is then reviewed. On the other hand,the periodic but unsolicited submittal of final design
data to the NRC by an applicant constructing a nuclear powerplant is not necessarily reviewed after
its submittal prior to formal application for theoperating license.
Before May 1973, when the deputy director forreactor projects issued a "Project Managers Handbook," there was no comprehensive, formally structured approach to the role of project management in
the various phases of the staff review of an application. The postconstruction permit (post-CP) period
i n particular was an ad hoc activity relative to themore structured process during the construction
permit or operating license review stages.
The project management of post-CP applications
was intended to include the project manager's fol-

lowup to resolve those matters documented in the
Safety Evaluation Report or the public hearing
record as items remaining to be resolved after thepermit was issued. Even so, once the CP was issued and the applicants' resources were heavily
committed to final design engineering and plant construction, resolution of these matters often was delayed due to changed priorities. Several factors
contributed to this phenomenon.
Unless specifically documented in the construction permit as a "condition" of the permit's validity,
no penalty to any party would result from deferral of
the post-CP matter until the operating license review. Early resolution of the matter prior to theoperating license review would usually benefit only
the permittee by providing a perceived certainty thatan acceptable solution had been obtained and that,as a result, his resource expenditures were definedand fixed. For the staff, this earlier resolution meant
a decision taken at an unnecessarily early time, thus
possibly foreclosing future decision options whichmight be indicated by additional information obtained later. As a result, these matters generally
were regarded to be of lower priority by the technical managers that allotted staff technical review
resources. Staff review schedules for these matterswere normally long, and expanded if an applicant
delayed his response to a staff information request.
The post-CP project, "inactive" relative to an
ongoing CP or operating license review, was more
li kely to be reassigned among the available project
managers during staff personnel and organization
changes. The project could also be transferredamong project management branches, further diluti ng management continuity. Such changes alsotended to diminish the perceived importance of vigorous pursuit of post-CP issues over periods ofmonths and sometimes years.
A number of post-CP requirements were identifled in the staff's Safety Evaluation Report for TMI2, including the following:• Further review of the applicant's status reports

on development of the inservice inspection proprogram• Review of the final design for aircraft protection• Further review of the Quality Assurance Programand• Continued review of all ACRS recommendations,
during construction

Except for the aircraft crash issue which was
resolved for the operating license for TMI-1, the document record of TMI-2 licensing activities does noti ndicate that these matters were pursued with Met
Ed during the construction period prior to the startof the operating license review. The aircraft crash79issue was reopened after additional data on airport
use became available (see Appendix 1.7).
Although systematic problems existed in efficiently resolving matters carried over from the CP
review into the post-CP period, the permittee andstaff generally agreed on the substance of and needfor the issues that had been identified but not
resolved during the construction permit review.
Two other kinds of post-CP issues were not so
defined, presenting additional stumbling blocks toearly resolution. These were the issues that arose
after the construction permit was issued. Neither
the AEC nor the NRC has developed a systematized, procedurally controlled method of conclusively
acting either on changes proposed by applicantsduring the post-CP period or on new regulatory requirements arising after the CP issuance that might
be required of these permittees. There are legal
and technical difficulties inherent in interpreting"principal architectural and engineering criteria,"
which form part of the basis for the construction
permit issuance and cannot be changed by the permittee without a construction permit amendment.
On the other hand, staff imposition of new requirements on permittees is legally constrained by 10
C.F.R. 50.109 which states that "the Commission
may... require the backfitting of a facility if it findsthat such action will provide substantial additional
protection which is required for the public healthand safety... " (Emphasis added.) Backfitting isdefined in the regulation as the addition, elimination,or modification of structures, systems or components of the facility after the construction permit
has been issued.
I n practice, these two types of issues have only
affected staff interaction with permittees during theperiod from issuance of the construction permit to
the applicant's submittal for an operating license.
Regulatory staff evaluation of changes identified tothe staff by an applicant during the post-CP periodi s often not completed until the operating license review. This is particularly true of complex issues thati nvolve controversy between staff and applicant.
But the consequences of this practice, in terms of
public risk, could be significant. It is probable, if notcertain, that staff requirements specified during an
operating li cense review, requiring hardware
changes (backfitting) in designs fixed by the applicant several years before, may be less technicallysophisticated (and more costly) than if the applicant
had been required to implement a staff position at
the time during construction when the modification
or addition could have been incorporated more
readily.

The
Regulatory Requirements Review Commit15
tee was established in early 1974 to create a permanent management committee with responsibility
for assessing the need for each new proposed
safety requirement and for making specific decisions regarding the imposition of each requirement.
( Additional discussion of this committee is presented in Section I.A.3.a.) The committee would consistof senior management representatives of the technical review divisions and the reactor project
management division. As originally intended, thecommittee would "review significant new regulatory
requirements or changes that provide significant relief from existing requirements, and to decide
whether, when and to what plants these changes
should be applied."
From the beginning, however, a program for implementation of new requirements, once accepted,
proved difficult to specify with clarity. Until September of 1975, decisions on new requirements documented in RRRC meeting summaries usually stated that the new requirement would be effective atsome future date, or at the earliest, "immediately," aterm interpreted to apply to all applications currently
i n process and to any future applications, but not torequire immediate modification of plants where theCP had been issued. At least twice1fi prior to July
1975, the committee instructed the staff to develop
or implement a comprehensive program for resolvi ng the matter of "backfitting" new or existing requirements to operating facilities licensed prior to
the development of the requirement. No such program was implemented, however. The summary of
the 31st meeting, issued September 24, 1975, announced that the RRRC would in the future categori ze its decisions and clearly delineate which of the
newly approved requirements would be required tobe "backfied" to all plants, whatever their status of
construction or operation. There was still nomanagement approved program to assure that staff
action was completed to effect the prompt implementation of each new "backfit" issue on theoperating plant to which the issue would apply,
however, and this situation prevailed through theti me of the TMI-2 accident in March 1979.
I n early 1973, the AEC licensing project manager
for TMI-2 had reported to his management that the
TMI-2 Final Safety Analysis Report would be submiffed in July 1973. This expectation was not met,and on October 26, 1973, Met Ed formally requested an extension of the dates set forth in the construction permit as the estimated earliest and latest
dates for completion of construction. The proposed
new dates were to be May 1, 1976 and May 1, 1977,80

4 years later than originally planned. Met Ed's stated reasons for the delay included unforeseen delays
i n engineering and procurement, additional engineering required to revise the FSAR to meet the
new AEC Safety Analysis Report guide and its subsequent Revision 1 (October 1972), difficulties inconstruction, difficulties in financing, additional work
necessary to meet the recent AEC Interim Acceptance Criteria for ECCS, the need for additional restraints on high energy systems outside containment,
and delays resulting from a decrease in the construction force to assure more effective quality control. The staff recognized the Met Ed delay and in a
letter of November 8, 1973, the director of regulation
urged that Met Ed submit their operating license application about 24 months before the scheduled fuell oading date for the plant. This set the date for submittal of the operating license application at about
May 1974.
Meanwhile, two reactor units similar to the TMI
units received operating licenses during 1973.
Oconee 1 and 2, constructed and operated by theDuke Power Company, started operation on Lake
Keowee in South Carolina. The TMI-1 plant received
an operating license in April 1974. Oconee 3, also
at the Lake Keowee site, began operation in July
1974.
e. The Operating License Review periodJanuary 1974 to February 1978
Summary

On February 15, 1974, Met Ed submitted the application for an operating license for TMI-2. This included the FSAR and other general information as
required by 10 C.F.R. 50.34. The FSAR was organi zed in accordance with the staff's guidance contained in the "Standard Format and Content of Safety Analysis Reports for Nuclear Power Plants," Revision 1, dated October 1972. The new licensing project manager, who had been assigned in October
1972, met with the technical reviewers assigned tothe acceptance review for the project to brief themon their responsibilities. 17 This part of the review
process is designed to yield conclusions, based ona few hours of work by each reviewer, covering thecompleteness of the information supplied by the applicant. The project manager advised the reviewersof staff and ACRS concerns arising from the CP review, findings during onsite inspections during construction, testimony at the CP hearings in 1969, andpotential new requirements developed by the staff
during the years since the issuance of the CP.

81

On March 19,1974, the staff met with representatives of Met Ed, Babcock & Wilcox, General Public
Utilities, Burns and Roe, and Gilbert Associates todiscuss the results of the completed acceptance review, and to inform Met Ed of the additional information required to complete the FSAR as necessary
for the staff to begin the operating license review.
The application with Amendment 13 to the FSAR
was accepted and docketed for operating license
review on April 4,1974.
A staff review schedule was established, basedon an operating license issuance within 24 months.
This schedule was not met, however. The minimum
operating license review schedule for any plant is
set by plant construction progress, since an operati ng license (OL) cannot be issued until construction
i s certified as complete.18 Like most OL applications, the TMI-2 application was docketed muchearlier than necessary to complete the review before the plant was ready to load fuel. Staff experience has shown that as delays in plant completionare encountered, applicants' responses to staff concerns also are slowed, which in turn can result infurther schedule delays in staff actions. Of the 46
months between the April 1974 docketing of the OL
application and its issuance in February 1978, about
12 months were attributed to construction delays,
six months to Met Ed licensing delays, and fourmonths to staff delays. 18
By August 21, 1974, the first round of staff questions had been sent to Met Ed. This standard question and response method of review continued foranother 25 months until the staff's issuance of the
Safety Evaluation Report in September, 1976.
Another new Licensing Project 19
Manager, Harley
Silver, was assigned in May 1975.
The Safety Evaluation Report issuance was impeded both by staff delay in preparing questions
and evaluating responses, and by Met Ed delay inresponding to questions. Met Ed also encountered
delays in plant construction. As a result, in early
1976 a number of unresolved issues remained
between the applicant and staff. 20 I n May 1976, Met
Ed was predicting that the plant would be ready forfuel loading in July 1977, 21 which would have been
the earliest time that an operating license was needed.
At this time, in a letter to Met Ed, 22 the NRC project management branch chief responsible for the
TMI-2 review presented a revised schedule forcompleting the Safety Evaluation Report and taking
the project to ACRS review. This schedule assumed completion of the ACRS review by August
20, 1976. After still further schedule delays during

1976, however, the ACRS review was concluded in
October 1976. (See the discussion in the following
section entitled "The Role of the Advisory Committee in Reactor Safeguards (ACRS) in TMI-2 Licensi ng."). During 1977 and early 1978, additional delays
i n resolving outstanding issues further delayed issuance of the operating license until February 1978.
While hearings before the Atomic Safety andLicensing Board continued throughout 1977, they
were not the pacing event because an initial decision was issued during December 1977.
During the operating license review, a number of
events took place which could have left their markon the TMI-2 operating license review, the general
conduct of the licensing process, or its organizational elements. Some of these events were:. The design of the cooling towers for earthquakeor tornado resistance• The applicant's cost-benefit figures used to justify the need for the nuclear plant. The capability of containment structures and other buildings to withstand aircraft impact. The environmental radioactivity monitoring program. The flood protection system. The warnings and evacuation plans of both theapplicant and the Commonwealth of Pennsylvania. Gaseous radioactivity releases during normal
operation, The effect on local water quality of chlorinedischarge from the plant circulating water system
and• The effect of cooling tower plumes on the gaseous effluent from the plant• The creation of the Regulatory Requirements Review Committee in early 1974

• The creation of the NRC in January 1975
• The issuance of the Standard Review Plan in No•••••

The ASLB initial decision issued on December 19,
1977, 6 NRC 1185 (1977), authorized the director of
the NRR to "make such additional findings on uncontested issues as may be necessary to the issuance of a full-term operating license for that unit,
consistent with the terms of this Initial Decision."
The joint intervenors moved to stay the order on thebasis that the environmental review of the nuclear
fuel cycle had not correctly dealt with the effects ofradon (Rn-222) releases generated in the course of
the mining and milling of uranium. The appeals weredenied by both the Atomic Safety and Licensing Appeal Board (ALAB-456, January 27, 1978) and theCommission (order issued March 2, 1978). An
operating license was issued on February 8, 1978.
Legal maneuvering by the intervenors was continued in the case; the hearing record was ultimately
reopened, and litigation continues to this day. (Additional information on the ongoing hearing process
is summarized in the section entitled "The Hearing
Phase of TMI-2 Licensing," under Section I.B.1.e.)vember 1975 (see Appendix 1.5)
The reorganization of the Office of Nuclear Reactor Regulation in December 1975 (see Appendix
1. 4)
The issuance of the second through the sixth
ACRS Generic Issues letters23
The issuance of 61 new regulatory guides and 74
revisions to issued guides
A Congressional inquiry into staff regulatory
practice in 1976, precipitated by safety issues
raised by NRC staff members
The staff's continuing struggle to implement theStandard Review Plan, and the ultimate rejection24 of any attempt to "backfit" the acceptancecriteria to a number of plants in the licensing process, including TMI-2

The public hearing process began soon after the
ACRS review was completed in October 1976. The
public hearing was precipitated by the granting of ani ntervention request made by the Citizens for a Safe
Environment and the York Committee for a Safe Environment as joint petitioners. The Commonwealthof Pennsylvania was also granted permission to participate as an interested State.
In accordance with the Commission's rules, the
ASLB confined its hearing to the matters placed incontroversy by the parties. Several board hearing
sessions were held during the period of Marchthrough July 1977. Issues argued during the heari ngs involved the following:

The Role of the Advisory Committee on Reactor
Safeguards (ACRS) in TMI-2 Licensing
The documented ACRS review of the TMI-2 project at the operating license stage is contained inthree documents, the transcripts of subcommittee
and committee meetings, 25 and the subsequentl etter summary report to the NRC chairman by the
ACRS chairman (see Appendix 1.6). The ACRS discussed the Met Ed application with representativesof and consultants for the applicants, General Public
Utilities Service Corporation, the Babcock and Wil-• The environmental impact of thermal releases• The biological survey performed by theapplicant's consultant

82cox Company, Burns and Roe, Inc., and the NRC
staff. At that time, the application, which had beenreported on in the staff's Safety Evaluation Report,
was represented in part by the applicant's FSAR as
amended through Amendment No. 44. The operati ng license was ultimately issued based on the
FSAR through Amendment No. 62.
The ACRS letter noted several topics that thecommittee concluded needed more work by the applicants or the NRC staff or both. Some of these topics had more relevance to the TMI-2 accident thanothers, but on each topic, the committee's comments were more characteristic of earnest advice tobe followed in the indeterminate future than ofstrong recommendations which must be carried out
as a condition of a favorable ACRS report to theCommission. A sampling of these comments fromthe TMI-2 letter, but typical of ACRS letters on all
projects, follows:

l and Nuclear Station, Unit 2 can be operated at
power levels up to 2772 MWt without undue risk to
the health and safety of the public.

Thus, although the committee expressed a numberof reservations in a general way, it recommended no
explicit restraints or conditions on the issuance ofan operating license. The committee found that,
subject to certain "satisfactory completion," therewas "reasonable assurance" that TMI-2 could be
operated safely.
The adequacy of the emergency core coolingsystem was not a specifically reported concern, and
the ACRS apparently recognized and accepted,
without prejudice, that the staff and applicant werestill involved in work to complete the Met Ed justification of the ECCS design. As reported elsewhere
i n this licensing summary, the staff and Met Ed interaction concerning ECCS matters extended
through 1977 and even during 1978 after an operati ng license had been issued.
Generic issues noted by the ACRS included
some of the matters which later proved to be significant in the TMI-2 accident. As generic issues, however, these were by definition to "be dealt withappropriately ... as solutions are found." Issues havi ng TM!-2 accident significance were:• This ... should be reviewed and evaluated by the
•
•
•
•
•
•
•
•
•

NRC staff prior to operating at up to full power ...
The committee wishes to be kept informed.
This issue should be resolved in a manner satisfactory to the NRC staff.
The committee recommends that (staff andapplicant) ... continue to strive for an early resol ution of this matter in a manner acceptable to the
NRC staff.
The committee believes that appropriate test procedures to confirm ... should be developed.
The committee recommends that further review
be made ...
The committee recommends that studies bemade ...
The committee recommends that, prior to commercial power operation of TMI-2, additional
means ... should be in hand in order to provide
i mproved bases for timely decisions ...
The committee believes that the applicants andthe NRC staff should further review ... formeasures ... and that such measures should be
i mplemented where practical.
Those (generic) problems should be dealt withappropriately ... as solutions are found.

• Behavior of reactor fuel under abnormal conditions• I nstrumentation to follow the course of an accident• Maintenance and inspection of plants

The 14 issues raised by the ACRS were addressed by the staff in the March 1977 Supplement
No. 1 to the Safety Evaluation Report. All but five issues were considered closed out in Supplement No.
1. Of the remaining five, the staff closed out all but
one in their Supplement No. 2 issued in February
1978 concurrently with the issuance of the operating
license. The remaining issue involved the scheduled
i mplementation of required plant improvements toassure that staff requirements for fire protection
would be met. The operating license was conditioned to require that these improvements be completed prior to startup following the first regularlyscheduled refueling outage.
I n the 15 months between the ACRS review andi ssuance of the operating license, the staff declared
17 plant specific issues other than those raised by
the ACRS to be resolved through staff and applicant
i nteraction. The FSAR was formally changed 18
ti mes. Nevertheless, in February 1978, five remaini ng issues required specific conditions in the license.
Although the ACRS received copies of all

The committee's conclusion on the review was asfollows:

The Advisory Committee on Reactor Safeguards
believes that, if due regard is given to the items
mentioned above, and subject to satisfactory completion of construction and pre-operational testing,there is reasonable assurance that Three Mile Is83

In summary... , the Board finds that the radiologicaleffluent and environmental monitoring programs as
proposed by the Applicants and approved by the
Staff are adequate to measure and evaluate normal
radioactive effluent releases... and that active,
real-time detectors would add nothing to thepresent capability. We further find that the
response or effectiveness of both in-plant instrumentation and offsite personnel in the event of an
accident would not be aided or improved by suchdetectors... 29

correspondence on the docket, and theoretically
could have intervened with additional direction or
advice at any time, it was not involved in the review
and approval of any of these matters. The ACRS
review was formally concluded in October 1976.
The Hearing Phase of TMI-2 Licensing

Construction of TMI-2 was authorized in November 1969 by an initial decision of the ASLB after
a hearing in which there was no opposition to theplant. 26 On May 20, 1974, the Atomic Energy Commission provided opportunity to interested persons
to request intervention and a public hearing on the
proposed operation of TMI-2. The joint intervenors
presented numerous contentions which alleged various inadequacies relating to protection of the public27
health and safety and the environment.
Two of the joint intervenors' contentions were:

The joint intervenors did not appeal the licensing
board's decision on this issue.
The licensing board, in rejecting the joint intervenors' contention on the inadequacy of emergency
planning, found:[ T]hat the record supports the conclusion that [thisContention], in its entirety, is without merit, and that
the Staff has properly assessed the adequacy andworkability of the emergency response. We alsofind the emergency and evacuation plans to beboth adequate and workable.

The environmental radioactivity monitoring programof the Applicant's is inadequate to accurately
measure the dose delivered to the public during
normal and accident conditions. Only active, realtime detectors can determine what the actual dose
rate is. Furthermore, an array of offsite detectors
could greatly aid in possible evacuation plans. No
operating license should be granted until the Applicants provide a network of active radiation monitors.

The capability to successfully use the originallyapproved emergency plan was challenged by thejoint intervenors in the operating license hearing.
Witnesses testified on behalf of the staff, the applicants, and the Commonwealth of Pennsylvania.
This contention was the only one for which theCommonwealth presented prepared testimony andsubmitted proposed findings, and it adopted theapplicant's proposed favorable findings as its own.
31
The intervenors presented no prefiled testimony,but conducted extensive cross-examination andsubmitted proposed findings on this issue.
The intervenors challenged several assumptions
that they considered crucial to successful action inaccordance with the plan. These challenged assumptions were:

The warning and evacuation plans of the Applicants
and the Commonwealth of Pennsylvania are inadequate and unworkable. The plans assume that all
local and State officials involved are on 24-hour
notice and can be contacted immediately. They
further assume that all people notified will promptly
react and know how to respond and are trained to
do so. They also assume that the public which has
been assured that accidents are 'highly unlikely' or' highly improbable' will respond and allow themselves to be evacuated. No operating and evacuation plans are shown to be workable through live
tests.28• That appropriate State and local officials areavailable to be contacted any time they are needed• That such personnel, upon being notified, willknow the right thing to do and will do it promptly
because they have been so trained• That any members of the public that should be
evacuated will respond appropriately and will
permit themselves to be evacuated despite thel ack of drills or tests of the public response

The joint intervenors offered no extensive expert
testimony on these issues, however, and the licensi ng board rejected both as nonsupportable. Basing
its rejection of the radiation monitoring contention
on the testimony of witnesses offered by the NRC
regulatory staff and the applicant, the licensing
board said:

The board found that the preponderance of evidence supported all of the above assumptions, andthat the emergency and evacuation plans were both
adequate and workable.

With respect to the ability of active, real-time
detectors to aid in evacuation plans, such detectors
would again be of little or no value. Instrumentation
used to determine the severity of an accident, andthe need for any offsite emergency action, is located on site and is monitored from the reactor control
room.

board's decision on emergency planning to the84Atomic Safety and Licensing Appeal Board. Relying
on the record produced before the licensing board,
the appeal board rejected all of the intervenors' arguments. 32 The ASLAB's holding confirmed theevidentiary deficiency in the joint intervenors' case,and also found that:sue. 39 This matter had not been resolved as ofMarch 28, 1979. (Extracts from important board decisions have been reproduced in Appendix 1.7.)
The TMI-2 Operating License[E]xisting Commission regulations do not requireconsideration in a licensing proceeding of thefeasibility of devising an emergency plan for the(in the event of an accident) of persons
located outside of the low population zone.

The TMI-2 operating license issued on Februaryg 1978 contained numerous conditions and includan Attachment 2 specifying required preoperational and startup tests which could not be started
until many other specifically identified work items
were completed "to the Commission's satisfaction."
The authorized event sequence of initial fuel loading,cold shutdown, initial criticality (startup), and power
operation required written authorization from the
NRC prior to each new step in the sequence.
The TMI-2 license provides that

It is true that, for reasons which need not be discussed here , the applicants and the staff neverthel ess looked into the possible need for protective
measures within a 5-mile radius of the reactorand the intervenors were permitted to crossexamine on the evidence presented in this regard.
It scarcely follows from this fact, however, that thequestion of emergency planning at still greater distances from the LPZ boundary had to be exploredat the Intervenors' instance.

Metropolitan Edison Company is authorized tooperate the facility at a core power level of 2772
megawatts thermal. Prior to attaining that power
level, Metropolitan Edison Company shall comply
with the appropriate conditions identified in Paragraph (3) below and complete the preoperational
tests, startup tests and other items identified in Attachment 2 to this license in the sequence specified. Attachment 2 is an integral part of thisli cense.

The requirements for evacuation planning are rooted in 10 CFR Part 100, and that Part 100 assumes
releases of radiation based upon a hypothetical
major accident 'that would result in potential hazards not exceeded by those from any accident
considered credible.' Thus, what accidents might
conceivably occur at the particular plant in question is irrelevant to planning for emergency evacualion; that is based solely on the Part 100 hypothetical accident and the assumed releases of radioactivity resulting therefrom3

The "Paragraph (3)" and "Attachment 2" referred todescribe many incomplete work items in systems
and components clearly important to safety. The
practical result of this approach is that the license,
publicized as an authorization to operate at fullpower for 40 years, is actually only a permit to load
fuel and go to cold shutdown. Following that, an extensive remaining technical effort, including interaction with the NRC staff, is still required to get theplant to a full power operational status. As of September 1978, approximately 14 major work items
remained to be completed. TMI-2 did not reach fullpower operational status until November 1978.
From the time of the operating license issuance,
the TMI-2 plant was officially an "operating reactor"
as far as the NRC licensing process was concerned.
According to standard licensing process practice,
the organization nominally responsible for operating
reactors does not usually accept responsibility forthe newly licensed "operating" plant at that time. In
this case, TMI-2 did not become the responsibilityof the NRR's Division of Operating Reactors eventhough the TMI-1 reactor, in operation since 1974,
was already so assigned. When the TMI-2 accident
occurred in March 1979, formal responsibility for theplant remained with the Division of Project Management.

Not discussed at the hearing was the NRC program to review and concur in radiological emergency plans prepared by State governments, or the exi stence or status of any such plan for Pennsylvania.
The Commonwealth had been requested by34,35
the
NRC in 1975 to submit a State plan for review.
However, at the time of the accident, the Commonwealth did not have an NRC approved radiological emergency plan. 36 As far as can be determined,
the Commonwealth never submitted a Pennsylvania
Radiological Emergency Response Plan to the NRC
for review in response to the 1975 request, eventhough a recent General Accounting Office (GAO)
report 37 indicated that such a plan existed or was
being prepared.
A significant issue throughout the TMI-2 licensing
proceeding (as well as for that of TMI-1) has been
whether the public is adequately protected against
the hazards of an airplane crash into the plant. 38
The board agreed that additional evidence must be
taken on the probability of heavy aircraft crashes
i nto the plant, with one member dissenting, in part,on the grounds that the operating license shouldhave been suspended pending decision on this is-85This delay is largely attributable to the reluctanceof the DOR to accept responsibility for a plant whena significant number of safety issues still remain unresolved. Asserting this reluctance, the division refused to accept responsibility for TMI-2 in September of 1978, 40 and formal responsibility was nottransferred to the DOR until August 22, 1979. 41 The
project management responsibility for all of the
B&W operating reactors other than TMI-2 was with
the Operating Reactors Branch No. 4 in DOR.42
The licensee's first contact point with NRC is Inspection and Enforcement, 43 which determines
whether additional NRC help is needed to resolve a
particular matter. This is an important change fromthe way the review process works prior to license
issuance, when the assigned project manager for
the DPM is the principal NRC contact with Met Ed.
During the period between February 1978 andMarch 1979, several licensing actions took place.
(These actions are described in Section I.A.2.)

3. Cost of site and site preparation
4. Construction labor rates and productivity

Studies for siting the nuclear unit that eventuallybecame TMI-2 began in 1967, and this unit was tobegin operation at about the same time as TMI-1,
1973 or 1974. Of the six sites considered in the region, Oyster Creek, New Jersey was initially selected, largely because of the local need for additional
generation capacity and the associated transmission cost savings attendant to plant construction inthat area. However, Met Ed re-examined the siting
i ssue in 1968 and decided that the TMI site had certain economic advantages over Oyster Creek basedon a planned 1973 operating date. In December
1968, the decision was made to construct a second
unit at TMI.

Offssite Radiological Impacts

Operating License Review Issues Having TMI-2
SignificanceThe licensing of a nuclear plant entails NRC staff
judgments on a large number of radiological safetyi ssues. The following review focuses on several
specific issues relevant to the TMI-2 special inquiry.

Site Selection

At the time the Three Mile Island site was selected for Unit 1, five sites had been considered by thethen joint applicants, Met Ed, JCPL, and Pennsyl44
The alternative site
vania Electric Company.
evaluation was done in 1965 and 1966, prior to a CP
application i n May 1967. The sites considered were:
1. Three Mile Island
2. Gilbert Station site on the Delaware River in New
Jersey3. Portland Station site on the Delaware River inPennsylvania
4. Monocacy site on the Schuylkill River, south of
Reading Pennsylvania
5. Berne site on the Schuylkill River, north of
Reading

All of the considered sites were roughly
equivalent in their distance from population centers,
a major consideration. Foundation conditions, including exposure to seismic disturbances, likewise
did not significantly vary at these sites. The ultimate
selection of TMI-1, intended to be operating by 1973
or 1974, was based on the following considerations:
1. Availability and cost of cooling water
2. Transmission investment and transmission losses

86

Met Ed analyzed and reported on a numbei =- ofaccidents and anticipated transients in its Final
Safety Analysis Report. The staff selected certainof these analyses as representative of events forwhich the offsite dose consequences would be conservatively greater than the other accident sequences analyzed by Met Ed. For these selectedsequences the staff independently calculated thepotential consequences.
The radiological consequences of selected"design basis" accidents were examined by the staff
i n two kinds of review activities. One was the radiol ogical safety review, concerning the maximum dosethat an individual would receive while standing oneither the plant exclusion boundary or the edge ofthe defined low population zone.
A second review
presented the results of similar analyses in terms ofboth the dose to an individual on the plant boundary
and the integrated dose to the total estimated popul ation within 50 miles of the site. 46 I n each of thesereports, the staff found that the calculated doses,
which were considered to be either realistic or very
conservatively calculated for the specific accidents
analyzed, represented very low and acceptablerisks to the public. The staff's Safety Evaluation
Report stated that the calculated potential offsite
doses due to design basis accidents were less thanthe offsite dose guidelines of 10 C.F.R. 100.
Thereafter, in section 7.0 of the supplement to the
Final Environmental Statement the staff reported
that the estimated integrated exposure of the popul ation within 50 miles of the plant from each postul ated accident would be orders of magnitude smaller
than that from naturally occurring radioactivity.
No hypothetical sequences of failures more
severe than the postulated "design basis" accidents
were considered because their probability of oc-

currence was thought to be sufficiently low to preclude consideration. The staff's environmental
statement explicitly embodied this approach, referring to guidance issued by the Commission in theform of a proposed annex to Appendix D, 10 C.F.R.
Part 50, 48 which has never officially been made apart of the regulations. From the time of its 1971
publication to this date, this proposed annex has
constituted the highest level and most recent document promulgated by the NRC explaining what aClass 9 accident is and why such accidents are to
be excluded from consideration in the licensing process:"ECCS Analysis of B&W's 177-FA Lowered Loop
NSS." The evaluation model required by Appendix
K to 10 C.F.R. 50 was documented in BAW-10104.
BAW-10103 described the application of the model
to evaluate the consequences of a range of sizes ofhypothetical pipe breaks in order to analyticallydemonstrate compliance with 10 C.F.R. 50.46.
I n the September 1976 Safety Evaluation Report,
the staff stated:
The emergency core cooling system for Three Mile
Island Unit 2 complies with 10 CFR Part 50.46 and
10 CFR Part 50, Appendix K, and is acceptable,
pending completion and review of the issues identified in our review of BAW-10103 (request for additional small and transition break analyses), and verification that these are applicable to Three Mile Island Unit 2. These analyses are expected to besubmitted by December, 1976.

The occurrences in Class 9 involve sequences of
postulated successive failures more severe thanthose postulated for establishing the design basis
for protective systems and engineered safety
features. Their consequences could be severe.
However, the probablity of their occurrence is sosmall that their environmental risk is extremely low.
Defense in depth (multiple physical barriers), quality
assurance for design, manufacture, and operation,
continued surveillance and testing, and conservative design are all applied to provide and maintainthe required high degree of assurance that potential
accidents in this class are, and will remain, sufficiently remote in probability that the environmental
risk is extremely low. For these reasons, it is notnecessary to discuss such events in applicants'
Environmental Reports.

The staff reviewed additional analyses submitted
by B&W in December 1976, and approved B&W's
small break analyses for their 177 fuel assembly,
l owered loop steam design, on February 18, 1977.
Although several calculational model changes werereported by B&W after February 1977 and were
subsequently approved by the staff, the small breakanalyses completed prior to February 1977 wereshown to be acceptably conservative. The final
Safety Evaluation Supplement No. 2, issued February 1978, stated that "studies of the spectrum of
breaks have been completed and are in accordancewith the emergency core cooling system acceptance criteria, and are acceptable."
The smallest break postulated by B&W at thatti me was 0.04 square feet at the reactor coolant
pump suction. B&W concluded that:

Thus all persons or groups necessary to approving
the operating license for TMI-2 tacitly accepted thatthe conservatively calculated doses reported in the
Safety Evaluation Report, being within 10 C.F.R. Part
100 guidelines for the postulated accidents examined, were in fact the necessary and sufficientdemonstration of an acceptable level of risk from
accidental releases of radioactivity. Further, each of
the accident sequences evaluated was based on
the staff's "single active failure" criteria, which did
not include assumptions of personnel actions that
could or would degrade emergency cooling functions in the reactor coolant system or secondary
system, or both. Figures 1-4 and 1-5 show theoffsite dose consequences as reported in the staff's
Final Environmental Statement and SER. Finally,
even though the TMI-2 project had been exceptedfrom adherence to the Standard Review Plan usedin staff reviews after 1975, the offsite dose consequence analyses and results therefrom met the staff
guidelines and acceptance criteria as contained in
the staff Standard Review Plan in February 1978.

[F]or breaks less than or equal to 0.04 square foot,the HPI [high pressure injection] alone is capable ofmatching decay heat boiloff and maintaining a liquid
inventory49
sufficient to preclude any temperature excursions.

Emergency Core Cooling System
The Met Ed Final Safety Analysis Report incorporated, by reference, B&W topical reports BAW10104, "B&W's Evaluation Model," and BAW-10103,

87

Significant assumptions made for this analysis included the continued operation of at least one of
two redundant HPI systems, a reactor coolant pump
trip and coastdown coincident with reactor trip, andthe availability of the auxiliary feedwater system.
None of these conditions were met during the TMI-2
accident.
Still further changes in small break analyses werereported by B&W and resolved with the staff during
1978, after TMI-2 licensing. The 1978 revisions in
the detailed justification of emergency core coolingsystem performance for the smallest break did notchange the conclusion reached earlier, that a 0.04square foot break would not result in any significant
fuel element cladding temperature increase. The revised calculations, approved by the staff, showedthat after 50 minutes, the HPI flow would exceed thefluid mass loss due to boil off through the break,and that prior to 50 minutes the fluid mixture level
would not drop below the top of the core. Again, a
key assumption in the analysis, but not realized in
the TMI-2 accident, was that ECCS flow from atl east one HPI pump would be continuously available
from the time of its automatic initiation.
During 1976, 27 separate generic safety issues
were raised by several NRC staff members who feltthat the staff's consideration of these issues was
deficient. These issues became the subject of extensive discussions in various settings, including the
ACRS and Congressional Committees. The issues
were not discussed in the staff technical review asreported in the Safety Evaluation Report of September 1976 or its two subsequent supplements ofMarch 1977 and February 1978. Each of the issues
was addressed in staff testimony introduced in the
public hearing held on the TMI-2 project, and foreach issue, the staff found that operation of TMI-2
could be authorized.
One of the 27 issues relevant to the TMI-2 accident concerned the potential consequences of ani nterruption in design ECCS flow within a few
minutes after its automatic initiation. As originallydescribed by a staff member, the interruption in flow
was possible because operators in some plants
were required to reset the safety injection signal 2
minutes after the occurrence of the signal. Reset isthe manual cancellation of the safety injection logic
signal, which causes power to be supplied to engineered safety features loads, including the ECCS
and related support systems. While reset does notof itself turn off the ECCS loads (pump, valve, andfan motors) which are already drawing power, asubsequent loss of offsite power would require
prompt operator action to manually restart them.
This is because the automatic control logic for startup of emergency diesel generators would cause
sequential loading of normal shutdown cooling loads(not ECCS loads, in the absence of the safety injection signal) in some designs, and no loads at all insome other designs.
I n considering this issue, the ACRS concluded
that a loss of offsite power subsequent to the safety
i njection signal should be considered in accident
analyses whether or not the safety injection signal
could be reset, because in either case a delayedl oss of offsite power would cause some interruptionof ECCS flow while electrical loads were beingtransferred to the diesel generator.51 Until this time,
the staff had postulated in the design basis analyses
that offsite power was lost coincident with a lossof-coolant-accident. All of the discussions that took

place on this matter focused on the design basis
large-pipe break LOCA, but not on small break analyses. For the large LOCA, the break and the safety
i njection signal occur almost simultaneously because of the very rapid depressurization, whereas
for the small breaks the safety injection signal itself
could be delayed, and was for approximately 2
minutes in the TMI-2 case. The effect of later ECCS
i nterruption on the smaller break accidents is unknown.
While the ACRS noted that the consequences ofi nterruption in ECCS flow should be examined because at that time it was seen that an offsite power
loss could cause the interruption, another cause ofinterruption is now obvious-if permitted by designand encouraged by procedures and training, an
operator may erroneously reduce or terminate
ECCS flow in the first crucial minutes of a depressurization event, such as occurred at TMI-2 forwhat amounted to a very small break.
The NRC's conclusions reported in November
1976, prior to ACRS review, were:52
1. Inspection and Enforcement (IE) would review
operating pressurized water reactors to assurethat all safe shutdown loads would automaticallybe picked up following an operator action toreset the safety injection signal.
2 IE would also examine emergency procedures tobe followed in the event of a LOCH to assure thatthe procedures do not permit safety injection
reset earlier than 10 minutes following the accident signal, unless such action was shown tobe necessary in the interest of safety.
3. There was no basis for changes in current
operating licenses or for changes of staff priority
i n considering the issue.
The staff testified at the TMI-2 hearing on May
18, 1977, concerning each of the 27 issues, that no
major change in regulatory requirements wasnecessary to assure the health and safety of the
public. Concerning Issue No. 4, "Loss of Offsite
Power Subsequent to Manual Safety Injection Reset
Following a LOCA," the following testimony was
given:
This issue applies in general to Westinghouseplants; it is not applicable to Three Mile Island Unit
2. This plant design does not require system SIS(safety injection signal) reset to permit further
operator action. Control is retained of individualcomponents. After a postulated loss of offsite
power following a LOCA, as long as the actuating
signal exists, ECCS loads would be automaticallysequenced onto the emergency diesels. (Emphasis added.)88

CLASSIFICATION OF POSTULATED ACCIDENTS AND OCCURRENCES(FROM FINAL ENVIRONMENTAL STATEMENT, DECEMBER 1972, SECTION VI)
CLASS

AEC DESCRIPTIONAPPLICANT'S EXAMPLE(S)1

TRIVIAL INCIDENTS

NONE

2

SMALL RELEASES OUTSIDECONTAINMENTSPILL IN SAMPLE HOOD

3

RADWASTE SYSTEM FAILURE

I NADVERTENT RELEASE OF WASTEGAS DECAY TANK4FISSION PRODUCTS TO
PRIMARY SYSTEM (BWR)NOT APPLICABLE

5

FISSION PRODUCTS TO
PRIMARY AND SECONDARYSYSTEMS (PWR)

ONE DAY OPERATION WITH PRIMARYSYSTEM LEAK TO REACTORBUILDINGNORMAL OPERATION WITH STEAM
GENERATOR TUBE LEAK AND
RELEASE FROM CONDENSER

6REFUELING ACCIDENTS

DROP OF FUEL ASSEMBLY OR DROP
OF HEAVY OBJECT ON FUELASSEMBLY

7

SPENT FUEL HANDLINGACCIDENT

DROP OF FUEL ASSEMBLY

8

ACCIDENT INITIATIONEVENTS CONSIDERED IN
DESIGN BASIS EVALUATIONI N THE SAFETY ANALYSISREPORTUNCOMPENSATED OPERATINGREACTIVITY CHANGESSTARTUP ACCIDENT
ROD WITHDRAWAL ACCIDENT
COLD WATER ACCIDENTLOSS OF COOLANT FLOW ACCIDENTSTUCK-OUT, STUCK-IN, OR DROPPEDCONTROL ROD ACCIDENTLOSS OF ELECTRIC LOAD ACCIDENT
STEAM LINE FAILURE
STEAM LINE LEAKAGE
STEAM GENERATOR TUBE FAILURE
ROD EJECTION ACCIDENTLOSS OF COOLANT ACCIDENTWASTE GAS TANK RUPTURE

9

HYPOTHETICAL SEQUENCES
OF FAILURES MORE SEVERE
THAN CLASS 8NONEFIGURE 1-4.

89

SUMMARY OF RADIOLOGICAL CONSEQUENCES OF POSTULATED ACCIDENTS(SINGLE UNIT ONLY)

CLASS

ESTIMATED FRACTION ESTIMATED DOSE
OF 10 CFR PART 20
TO POPULATION
LIMIT AT SITE
I N 50 MILE
BOUNDARY *RADI US, MAN-REM

EVENT

1.0

TRIVIAL INCIDENTS

**

**

2.0

SMALL RELEASES OUTSIDECONTAINMENT

**

**

3.0

RADWASTE SYSTEMFAILURES

3.1

EQUIPMENT LEAKAGE OR
MALFUNCTION

0.073

10

3.2

RELEASE OF WASTE GASSTORAGE TANK CONTENTS

0.29

40

3.3

RELEASE OF LIQUID WASTE
STORAGE TANK CONTENTS

0.003

0.47

4.0

FISSION PRODUCTS TO
PRIMARY SYSTEM (BWR)

N.A.

N.A.

5.0

FISSION PRODUCTS TO
PRIMARY AND SECONDARYSYSTEMS (PWR)

5.1

FUEL CLADDING DEFECTS
AND STEAM GENERATOR
LEAKS

**

**

5.2

OFF-DESIGN TRANSIENTSTHAT INDUCE FUELFAILURE ABOVE THOSEEXPECTED AND STEAM
GENERATOR LEAK

. 002

0.23

5.3

STEAM GENERATOR TUBE
RUPTURE

0.096

13

6.0

REFUELING ACCIDENTS

6.1

FUEL BUNDLE DROP

0.015

2.1

6.2

HEAVY OBJECT DROP ONTO
FUEL IN CORE

0.26

36

7.0

SPENT FUEL HANDLINGACCIDENT
FIGURE I-4-Continued
90

CLASS

EVENT

7.1

FUEL ASSEMBLY DROP IN
FUEL STORAGE POOL

7.2

ESTIMATED FRACTION ESTIMATED DOSE
OF 10 CFR PART 20
TO POPULATION
LIMIT AT SITE
I N 50 MILE
BOUNDARY *RADIUS, MAN-REM
0.01

1.3

HEAVY OBJECT DROP ONTO
FUEL RACK

0.038

5.3

7.3

FUEL CASK DROP

N.A.

N.A.

8.0

ACCIDENT INITIATIONEVENTS CONSIDERED I N
DESIGN BASIS EVALUATIONI N THE SAFETY ANALYSISREPORT

8.1

LOSS-OF-COOLANT ACCIDENTS
SMALL BREAK

0.16

40

LARGE BREAK

1.2

1000

8.1(a)

BREAK IN INSTRUMENT
LINE FROM PRIMARY SYSTEM THAT PENETRATESTHE CONTAINMENT

N.A.

N.A.

8.2(a)ROD EJECTION ACCIDENT(PWR )

0.12

100

8.2(b)ROD DROP ACCIDENT (BWR)

N.A.

N.A.

8.3(a)STEAMLINE BREAKS (PWR'sOUTSIDE CONTAINMENT)SMALL BREAK<0.001<0.1

LARGE BREAK<0.001

0.13

N.A.

N.A.

8.3(b)STEAM LINE BREAKS (BWR)*REPRESENTS THE CALCULATED FRACTION OF A WHOLE BODY DOSE OF 500
MREM OR THE EQUIVALENT DOSE TO AN ORGAN.
**THESE RELEASES WILL BE COMPARABLE TO THE DESIGN OBJECTIVES INDICATED IN THE PROPOSED APPENDIX I TO 10 CFR PART 50 FOR ROUTINE EFFLUENTS (I.E., 5 MREM/YR TO AN INDIVIDUAL FROM EITHER LIQUID OR GASEOUS
EFFLUENTS).

FIGURE I-4-Continued

91

15.3

RADIOLOGICAL CONSEQUENCES OF ACCIDENTS

15.3.1

GENERAL
AS NOTED IN THE SAFETY EVALUATION REPORT, WE HAD PREVIOUSLYCONCLUDED THAT WITH A CONTAINMENT LEAK RATE OF 0.13 PERCENTPER DAY AND A DOSE REDUCTION FACTOR OF 6.6, THE OFFSITE DOSEGUIDELINES OF 10 CFR PART 100WOULD BE MET.
WE HAVE REVIEWED THE REVISED SPRAY ADDITIVE SYSTEM DESCRIBEDI N SECTION 6.2.3 OF THIS SUPPLEMENT, AND CONCLUDE THAT THIS SYSTEM, ALTH000H SLIGHTLY LESS EFFECTIVE FOR IODINE WASHOUT THAN
THE SYSTEM ORIGINALLY PROPOSED IN THAT IT DOES NOT REMOVE THE
ORGANIC FORM OF IODINE, RESULTS IN A SUFFICIENTLY RAPID ABSORPTION OF THE DOMINANT ELEMENTAL FORM TO MEET THE OFFSITE DOSEGUIDELINES OF 10 CFR PART 100WITH A CONTAINMENT LEAK RATE OF
0.13 PERCENT PER DAY. TABLE 15.1 HAS BEEN COMPLETED TO SHOW THE
POTENTIAL OFFSITE DOSES RESULTING FROM THE POSTULATED LOSSOF-COOLANT ACCIDENT.

15.3.2

DESIGN BASIS ACCIDENT ASSUMPTIONSI N THE SAFETY EVALUATION REPORT, WE HAD NOT COMPLETED SUBPARAGRAPH 4 OF THIS SECTION COVERING ASSUMPTIONS DEALING WITHI ODINE REMOVAL. BECAUSE THE APPLICANT HAS NOW PROVIDED AN
ACCEPTABLE SPRAY ADDITIVE SYSTEM, THESE PARAMETERS ARE LISTEDBELOW.
4.

I ODINE REMOVAL BY THE CONTAINMENT SPRAY SYSTEM WAS BASEDON:
6
SPRAYED CONTAINMENT VOLUME 1.764 X 10 CUBIC FEETUNSPRAYED CONTAINMENTVOLUMEMIXING RATE BETWEENSPRAYED AND UNSPRAYEDREGIONSI ODINE REMOVAL COEFFICIENTSELEMENTALORGANICPARTICULATEELEMENTAL IODINE DECONTAMINATION FACTOR

3.950 X 10 5 CUBIC FEET

2.0 TURNOVERS OF UNSPRAYEDVOLUMES PER HOUR PLUS
18 000 CUBIC FEET PER
MINUTE
10.0 HOURS -1
00.4 HOURS -1
100

FIGURE 1-5. Accident Analyses (From Safety Evaluation Report, TMI-2,
Supplement 1, March 1977)92

POTENTIAL OFFSITE DOSES DUE TO DESIGN BASIS ACCIDENTS

ACCIDENT

LOSS-OF-COOLANT

TWO HOUREXCLUSION BOUNDARY(610 METERS)COURSE OF ACCIDENTS
LOW POPULATION ZONE
( 3218 METERS)THYROID

WHOLE BODY

THYROID

WHOLE BODY

( REM)( REM)( REM)( REM)

280

8.2

108

2.1

POST-LOCAHYDROGEN PURGE DOSE

<1FUEL HANDLING

46

3

STEAM GENERATOR
TUBE RUPTURE

6<1

STEAM GENERATOR
TUBE RUPTURE
WITH IODINE SPIKE

76<1

STEAM LINE BREAK

2<1

LOSS OF OFFSITE
POWER

<1

<1

1

<1

GAS DECAY TANKRUPTURENEGLIGIBLE

6

NEGLIGIBLE<1

ROD EJECTION**
CASE 1
CASE II

24
102

<1
2

11
19

<1
<1

LOSS OF OFFSITE
POWER WITH COINCIDENTI ODINE SPIKE<1**ACTUAL ROD EJECTION DOSES WILL NOT EXCEED THE DOSES FOR CASE I (RELEASESTHROUGH THE CONTAINMENT) OR CASE II (RELEASES THROUGH THE SECONDARYSYSTEM).

FIGURE 1-5-Continued

93

Notwithstanding this disclaimer of the issue's
relevance to TMI-2, further work was done to assure that all pressurized water reactor facilities had
written procedures describing all necessary operafor actions to sustain operation of the emergency
diesel generator, ECCS, and related engineered
safety features after a loss of offsite power following
a LOCA, and subsequent to a safety i njection signal
reset.
A March 19, 1979 memorandum from IE to theDivision of Operating Reactors 53 stated that of 46
operating pressurized-water reactors inspected (including TMI-1 and TMI-2), 30 were found either not
to need any corrections because of inherent design
features, or already to have adequate procedures,and 16 were found to require procedure revision. All
deficient procedures were said to have beencorrected by December 31, 1978. However, an examination of emergency procedures effective on
March 28, 1979 (see Section II.C.1 of this report) indicates that, for a small break LOCA in particular,
the TMI-2 procedures include (1) an explicit direction
to bypass (reset) the safety injection system signal,and (2) a caution to restore, by manual action after
loss of offsite power, only the reactor building isolation and cooling functions, not any safety injection
function.
A curious factor relative to this issue is the wellknown and accepted staff review practice within the
Division of Systems Safety generally to refuse togive credit in safety analyses for operator actions
needed earlier than 10 to 20 minutes following a
54
Allowing an operator to electively terLOCA.
minate ECCS injection flow within the first 10
minutes "if necessary for safety" is inconsistent withthis practice. One might question the decision to all ow any elective degradation of design flow during ati me of great demand on the operator's decisionmaking capability (increasing the potential for error),
if that is not necessary to safety. On the other
hand, if it is necessary to safety, allowance of themanual action would appear to be in direct conflictwith established regulatory practice disallowing required manual actions early in an accident sequence.
The regulatory staff's evaluation of whether licensees are justified in concluding that prohibiting safety injection system reset for 10 minutes is not in thebest interest of safety is still underway. Work onother matters considered of higher priority has displaced any progress on this part of the issue sincegathering responses from a number of licensees inl ate 1977. Regarding the ACRS concern about theloss of power at any time subsequent to ECCS ini-

tiation (even without any adverse operator action),again no further staff analysis has been reported.
55
The ACRS concern has, since March 1978,
beenclassed as a generic issue to be managed by theTechnical Activities Steering Committee. The matter
now is the responsibility of the Unresolved Safety
I ssues Task Force.
Onsite Radiological Protection

Met Ed had proposed ventilation systems
designs acceptable to the staff as of the time of the
Safety Evaluation Report issuance in September
1976. The staff agreed in the Safety Evaluation Report that the systems were designed to assure that
personnel are not exposed to normal or abnormal
airborne concentrations exceeding those in 10
C.F.R. Part 20 by (1) maintaining air flow from areasof low radioactivity potential to areas of high radioactivity potential (2) preventing recirculating air in
the auxiliary and fuel buildings (3) maintaining anegative pressure in the auxiliary and fuel buildings
with respect to the atmosphere and (4) periodicallypurging the containment structure with outside air
through high efficiency particulate air and charcoal
filters.
When the operating license was issued in February 1978, an exemption from NRC requirements on
the quality of the charcoal in the fuel handling buildi ng air cleanup system was allowed until the first
regularly scheduled refueling outage, at which time
the charcoal was to be replaced. This had been requested by Met Ed on the basis that the initial loadi ng of charcoal had been specified and purchased
prior to a revision in NRC requirements (Regulatory
Guide 1.52, Revision 1, July 1976), and that laboratory testing of the charcoal indicated filtration efficiency only slightly less than the new NRC requirement.
The exemption was granted by citing in the operati ng license the specific sections of the technicalspecifications which would be exempted. However,an additional section was erroneously cited which
exempted the requirement to test the charcoal after
each 720 hours of use. This error was the apparent result of incomplete checking by qualified
NRC technical personnel of a "last minute" change
incorporated within a day or two of the issuance ofthe operating license on February 8, 1978. The
resultant elimination of the requirement to periodically test the charcoal, which did not quite meetstandards at installation, set the stage for the undetected degradation of the charcoal that probably
did occur. The charcoal adsorber was important for94was exercised in the TMI-2 review only to the extent of assuring that certain plant or system variables were selected for monitoring, that the appropriate instruments would have assured safetygrade power sources, and that the systems were
expected to survive postulated accident environments to provide information to plant operators. Installed postaccident monitoring instrumentation andthe availability of that instrumentation for TMI-2 wasdocumented in Tables 3.3-10 of the technical specif57
i cations which is reproduced here as Figure 1-6.
The issue of postaccident monitoring also arose
during the late 1976 consideration of the 27 issues
raised by staff members. Issue No. 21, "Instruments
for Monitoring Both Radiation and Process Variables
58
reflected the staff position that
During Accidents,"
radiological effluent and area monitoring are not relied on as a primary means of coping with postulated accidents. Testimony on the 27 generic issues
at the TMI-2 operating license hearing reiterated thestaff position, and stated that there were no radiation monitoring systems at TMI-2 that were required
to automatically activate emergency equipment to
mitigate the consequences of the LOCA. This was
based in part on the assumption that the safety
features actuation system would initiate containment
isolation on the detection of a 4-psig pressure in thecontainment. The testimony stated that:removal of radioactive iodine from the fuel handlingbuilding and auxiliary building atmospheres.
Following the operating license issuance, modifications in the heating and ventilating systems of thefuel handling building and auxiliary building, discussed in more detail in the IE investigation into
56
resulted in continuous flow through these
TMI-2,
filters. The staff originally approved the filters, system design, and operational surveillance procedureson the basis that the filters would normally be
bypassed and would be used only when needed tofilter air expected to contain some radioactive
iodine. The staff was not informed of the designchange by Met Ed, and the filter charcoal was nottested between March 1978 and March 29, 1979. It
is concluded (see Section II.B.2) that the operating
history of the filters significantly degraded the removal efficiency of the carbon filter material prior to the
TMI-2 accident.

Instrumentation to Monitor the Course of an
Accident

At the issuance of the Safety Evaluation Report in
September 1976, the postaccident monitoring instrumentation was considered an open issue only
because of the lack of justification that the instrumentation would survive a design basis earthquake.
This concern was subsequently reported resolved in
Supplement No. 1, issued in March 1977, and Supplement No. 2 of February 1978. The staff accepted
the Met Ed proposals on the basis of (1) an analytical verification of structural integrity, (2) the potential
availability of backup information from portableequipment, and (3) the similarity of the instruments
to other seismically qualified components. No
evaluation of the equipment with respect to postaccident environment design criteria was reported.
Equipment qualification for the postaccident environment in general was and is a continuing andcontroversial design issue. Postaccident environmental criteria have for several years been selectedconservatively to envelope those conditions expected within containment following the design basis
LOCA events analyzed in the applicant's Safety
Analysis Report. Design basis accidents have bydefinition precluded core damage greater than that
expected in the large-pipe break LOCK Thispredicted environment has included radiation levels
characteristic of relatively much less core damage
and radioactivity released to the containment thanoccurred at TMI-2. Staff review responsibility, vested primarily in the electrical instrumentation branch
and the technical specifications development group,[T]he staff determined that gaseous release fromthe reactor containment would be isolated from theenvironment by the action of the Safety Features
Actuation System and that there would be no flowof containment gases through either the reactor
containment purge monitor or through the plantvent monitor.

As the TMi-2 event would later demonstrate, thestaff's position quoted above is an example of the
problems inherent in its focus on the large break
LOCA event which would have quickly pressurized
the containment sufficiently to cause isolation. At
TMI-2, the 4-psig containment pressure, which was
the only signal that would isolate the containment,
was not reached for about 4 hours after the accident, partly because of manual actions taken by
the operators to activate the building's selfcontained cooling and ventilation system. Duringthat time some 8000 gallons of reactor coolant water (that had been released through the pressurizer
relief valve) and contained gases were inadvertently
transferred out of containment.
The staff's Standard Review Plan had since November 1975 specified criteria that required diverse
containment isolation signals. But TMI-2, as an
operating license application that was docketed pri-95

I NSTRUMENTATIONPOSTACCIDENT INSTRUMENTATION
LIMITING CONDITION FOR OPERATION

3.3.3.6 THE POSTACCIDENT MONITORING INSTRUMENTATION CHANNELS SHOWNI N TABLE 3.3-10 SHALL BE OPERABLE.
APPLICABILITY: MODES 1, 2, AND 3.
ACTION:A.

WITH THE NUMBER OF OPERABLE POSTACCIDENT MONITORINGCHANNELS LESS THAN REQUIRED BY TABLE 3.3-10, EITHER RESTORE
THE INOPERABLE CHANNEL TO OPERABLE STATUS WITHIN 30 DAYS, OR
BE IN HOT SHUTDOWN WITHIN THE NEXT 12 HOURS.

B.

THE PROVISIONS OF SPECIFICATION 3.0.4 ARE NOT APPLICABLE.

SURVEILLANCE REQUIREMENTS

4.3.3.6 EACH POSTACCIDENT MONITORING INSTRUMENTATION CHANNEL SHALLBE DEMONSTRATED OPERABLE BY PERFORMANCE OF THE CHANNEL CHECK AND
CHANNEL CALIBRATION OPERATIONS AT THE FREQUENCIES SHOWN IN
TABLE 4.3-10.

THREE MILE ISLAND - UNIT 2, PAGE 3/4 3-39
FIGURE 1.6. TMI-2 Postaccident Instrumentation(From TMI-2 Technical Specifications)96TABLE 3.3-10
POSTACCIDENT MONITORING I NSTRUMENTATIONMINIMUM CHANNELSOPERABLEI NSTRUMENT
1. POWER RANGE NUCLEAR FLUX

2

2. REACTOR BUILDING PRESSURE

2

3. CORE FLOOD TANK LEVEL

1/TANK

4. REACTOR COOLANT OUTLET TEMPERATURE

2

5. REACTOR BUILDING DOME RADIATION MONITOR

1

6. RC LOOP PRESSURE

2

7. PRESSURIZER LEVEL

2

8. STEAM GENERATOR LEVEL/STARTUP

1/STEAM GENERATOR

9. STEAM GENERATOR LEVEL/OPERATING

1/STEAM GENERATOR

10. BORATED WATER STORAGE TANK LEVEL

1

11. HIGH PRESSURE INJECTION FLOW

11LOOP

12. LOW PRESSURE INJECTION FLOW

1/LOOP

13. REACTOR BUILDING SPRAY PUMP FLOW

1

14. STEAM GENERATOR PRESSURE

1/STEAM GENERATOR

THREE MILE ISLAND - UNIT 2, PAGE 3/4 3-40

FIGURE 1-6-Continued97

or to January 1, 1977, was 59
specifically exempt fromthe Standard Review Plan.
Even so, Met Ed did
agree to install a reactor building dome radiation
monitor (see Figure 1-6), although the monitor was
not part of the containment isolation system.
Other instrumentation that either was or would
have been particularly valuable for monitoring thecourse of the accident is also not required by thelicensing process. This includes direct measurement of reactor core coolant temperatures, forwhich 52 thermocouples were available in 52 of theTMI-2 reactor fuel assemblies, and a direct measurement of reactor vessel water level, which is notavailable on any pressurized-water reactor. General Design Criterion 13 of 10 C.F.R. Part 50 requires
i nstrumentation to "monitor variables over their anticipated ranges for normal operation, ... and for accident conditions as appropriate to assure adequate
safety." This was not interpreted by the licensing
staff to require either direct reactor vessel waterl evel measurement or incore (vessel) thermocouples.

necessary to protect the public health and safety,
the regulated industry periodically argued, with partial success, that at least some of the NRC's requirements were excessive, unworkable, or both.
Beginning as early as 1969, the ACRS has called foran assessment and subsequent action by the staff
on this instrumentation issue. 62 The NRC issued
Regulatory Guide 1.97 on this topic in December
1975, then revised that guide in August 1977, but efforts to obtain industry implementation of the guidewere unsuccessful due to the applicants' opinions
that more definitive NRC direction was needed on
acceptable methods. of compliance. 63
Further
directions for implementing the guide were to be
developed under the NRC's Program for the Resolution of Generic Issues mandated by Section 210 of
the Energy Reorganization Act of 1974. At about
the same time the August 1977 Revision 1 of theguide was issued, the generic task plan to implement the guide was approved as Task A-34, "Instruments for Monitoring Radiation and Process
Variables During Accidents." 64 The approved problem description for that task indicated the depth ofthe lack of consensus on most of the specifics of
the issue, even though a regulatory guide had already been issued:

The ACRS had raised the issue of water level instrumentation with the staff and B&W during its review of the B&W standard nuclear plant design( BSAR-205). 60 B&W's position, unchallenged by
the NRC staff, was that the pressurizer level indication and other available reactor-coolant-systemmeasurement instrumentation provided were adequate for the trained operator to take effective action to correct a decreasing liquid level in the reactor coolant system. The subsequent ACRS letter
report to the Commission on BSAR-205 recommended that "a study be made of the merits of including instrumentation to sense the water level inthe reactor pressure vessel." 61 This was a matter ofgeneric interest to the ACRS and later became partof the staff's generic effort on all "instruments formonitoring radiation and process variables during
accidents," discussed in the following paragraphs.

To develop criteria and guidelines to be used byapplicants, licensees and staff reviewers to support
i mplementation of Regulatory Guide 1.97, Revision 1(Instrumentation for Light-Water-Cooled Nuclear
Power Plants to Assess Plant Conditions Duringand Following an Accident).
Such criteria and guidelines would provide specificguidance on functional and operational capabilities
required of the various classes of instruments, including in-plant and ex-plant instruments. Where
such guidance cannot be provided, the rationale tobe applied to derive requirements for specific situations will be provided.

Progress was made during 1978 under this task
plan and was reported on March 28, 1979, 65 withthe recommendation that Generic Task Activity A34 be considered completed.
Reactor vessel
coolant level was only one of more than 37 plant
operating parameters considered and determined to
be of importance, but for which backfitting of monitoring instrumentation on operating plants would not
be justified.
The TMI-2 accident gave impetus to a reconsideration of the generic issue, and the later work issummarized in a recent memorandum to Commissioner Ahearne. The current plan for resolution
calls, in part, for another revision to the Regulatory
Guide and for "prompt implementation by the Officeof Nuclear Reactor Regulation on66all operating
plants and plants under construction.

The provision of adequate instrumentation to foll ow the course of an accident has for years been acontroversial generic issue among the NRC, the
ACRS and the regulated industry. Basic issues
have included the plant variables to be measured,
the kinds of information needed about those variables, the instrument operating ranges necessary toadequately sense and display the variables
throughout the predicted durations of the accidents,
and the criteria, methods, and objectives of environmental qualifications testing for verification of the instruments.

Because of the technical complexity of the issues
i n controversy, and NRC's unwillingness or inability
to explicitly define what minimum requirements were98

Standard Review Plan. Assimilation of public comment on the Regulatory Guide resulted in publicationof Revision 1 in November 1977. Regulatory Guide
1.101 was declared by the Regulatory Requirements
Review Committee to be sufficiently important tosafety as to be applied to all plants, whether alreadyoperating or not. 69 However, as has been noted
earlier in this report, the RRRC decisions did not explicitly define when a new requirement must be met
by a licensee. In this case, the NRC decided to impose the newer requirements on licensees only
when the licensee proposed a revision to its emergency plan. 68
Met Ed submitted such a proposed revised plan
to the NRC in Amendment No. 65 to the FSAR dated May 11, 1978. As reported in an internal NRC
staff memorandum, 70 this revised plan was found to
be deficient with respect to the criteria of Regulation
Guide 1.101, Revision 1. This memorandum recognized that the emergency plan was considered toapply to the entire Three Mile Island site, encompassing the operations of both TMI-1 and TMI-2.
Nevertheless, Met Ed was never requested to consider and resolve the deficiencies due to internal
administrative delay resulting from split responsibility within NRR for the TMI-1 operating unit (Divisionof Operating Reactors) and the TMI-2 under operati ng license review (Division of Project Management).
Met Ed records show that the plant operating personnel modified emergency procedures based on
the revised plan (unapproved by NRC) submitted in
Amendment 65 to the FSAR. However, no basis forthe licensee approval of the revised plan was foundi n plant records, as is required by the plant technicalspecifications, sections 6.5.1.6, 6.5.1.7, and 6.8.
The implementation of the emergency plan was amatter of controversy in the operating license heari ng. (This is discussed in "The Hearing Phase of
TMI-2 Licensing," under Section I.B.1.e.)Emergency Plan

The licensing requirements regarding emergency
planning are described in 10 C.F.R. 50 Appendix E,
and center on the development of an acceptable
plan for actions to be taken in the event of declared
emergencies at the plant site. The plan involves thecooperation of certain State and local government
agencies, which the NRC secures at the time of emergency plan approval by obtaining written documents from appropriate State and local agencies indicating their intent and capability to act when notified of an emergency at the plant site.
Apart from such documented intent to cooperate
and provide appropriate services, NRC regulations
prior to March 28,1979 did not require that the NRC
approve the emergency plan of any organizational
entity other than the applicant. State and local
governments are not required to have nuclear emergency plans.67
The staffs review of the Met Ed emergency plan
was summarized in section 13.3 of the Safety
Evaluation Report in September 1976. The staff
concluded that the plan met the requirements of 10
C.F.R. 50 Appendix E, that it was responsive to thespecific requirements of the staff, and that it provided a basis for an acceptable state of emergency
preparedness.
Staff review of the Three Mile Island emergency
plan started with the plan for TMI-1. The staff's
Safety Evaluation Report of July 11, 1973, for theoperating license review of TMI-1 reported that the
emergency plan was acceptable. The criteria usedby the staff were those found in Appendix E to 10
C.F.R. Part 50, supplemented by a guidance document entitled, "Guide to the Preparation of Emergency Plans for Production and Utilization Facilities,"
dated December 1970. A revised emergency planfor the Three Mile Island site (to be effective during
emergencies initiating at either TMI-1 or TMI-2) was
submitted with the TMI-2 Final Safety Analysis Report in May 1974. The staff review of this plan wascompleted in August 1975 and reported in the staff's
Safety Evaluation Report for TMI-2 dated September 1976. This review was conducted at thesame time the initial Standard Review Plan wasunder development. The Standard Review Plan was
published in November 1975. The criteria in effectfor the TMI-2 review were nearly equivalent to thoseissued in section 13.3 of the Standard Review
Plan. 68
The initial version of Regulatory Guide 1.101, "Emergency Planning for Nuclear Power Plants," wasalso published for comment in November 1975. The
criteria found in Annex A of this guide are substantially equivalent to those found in Appendix A of theControl Room Design Requirements

The NRC review of electrical instrumentation andcontrols focused on the evaluation of systems andcomponents associated with reactor plant control,and even more narrowly, specifically with thosesystems and components associated with safetyrelated functions. Generally, GDC 13 and 19, sections 7 and 8 of the Standard Review Plan, and anumber of related regulatory guides that weredeveloped beginning in the early 1970s have notconsidered the integration of the control systems at
the operator-control interface to provide for efficient, safe utilization of the controls by one or more
operators. The TMI-2 control room design, now99that the applicant had "submitted a program indicati ng his plans to comply with the staff position."
At the license issuance in February 1978, thestaff concluded that TMI-2 could be licensed tooperate even though Met Ed had not yet installedsystems (including the emergency feedwater system) that would mitigate the consequences of asteam line break using only safety grade equipment.
74
However, the staff documented its reviewof theconsequences of both steam and feedwater line
breaks, with no credit given for the operation of thenonsafety grade equipment available, and concluded
that operation for the first fuel cycle would be acceptable. This conclusion is included as a condition
i n the operating license:

known to have been deficient in certain human factor aspects, was not evaluated with regard to thosefactors during either the construction permit oroperating license reviews. This topic is discussed
at length in the Human Factors section (see SectionII.E) of this report.

Emergency Feedwater System

Staff review of the Met Ed operating license application led to some changes in this systemdesign. 71 The design changes were all intended tomake the system less vulnerable to piping or equipment failures. The first set of inquiries to Met Ed in
August 1974 included this position statement by the
I nstrumentation and Control Systems Branch:Prior to startup following the first regularlyscheduled refueling outage, Metropolitan Edison
shall do the following:

We have concluded from the information presented
i n the FSAR concerning the Auxiliary Feedwater
System (AFS) that this system is essential to plantsafety and must be capable of satisfying its functional requirement after sustaining a break in its
piping inside containment and a single electricalfailure. We will require that the instrumentation,
control, and electrical subsystems associated with
the AFS be designed to conform to IEEE Std 2791971 and IEEE Std 308-1971. 72

Submit appropriate descriptions and analyses
and modify the secondary (main steam andfeedwater) systems so that the consequencesof a spontaneous break anywhere in a secondary system line will be mitigated only by safety
grade equipment, with nonsafety grade equipasment permitted to serve as a backup for the assumed single failure of safety grade equipment.
For those portions of the secondary systems
where a break might be caused by a seismic
event, Metropolitan Edison Company shall modify the systems so that accident consequences
will be mitigated only by seismic Category I
components after assuming single failure in any
seismic Category I component . 7

The term auxiliary feedwater system used by Met
Ed is synonymous with emergency feedwater system used by the staff.
Other requirements were also complied with by
Met Ed during the review to assure that total reliance was not placed on the "nonsafety grade" integrated control system and the air supply system,
which provided power for some diaphragm operati ng valves. By September 1976, the only qualification on the staff's endorsement of the emergency
feedwater system was that it was subject to final
review of the steam line break analysis. At that time
a potential controversy existed between the staff
and Met Ed over the need for, and quality of, automatic termination of both main and emergency
feedwater flow in the event of a steam line break.
The staff expected no particular problem inachieving a resolution of the then open issue at the
October 1976 meeting of the ACRS. The committee
recognized this and merely asked to be kept informed. 73 During 1977, the 27 issues raised by individual staff members (and which resulted in the
publication of NUREG-0138 and NUREG-0153) included one entitled "Treatment of Non-Safety Grade
Equipment in Evaluation of Postulated Steam Line
Break Accidents." Discussion of this issue with Met
Ed led to a resolution by the time of the public hearing 50 i n May 1977. As presented by the licensing
project manager at the hearing, the resolution was

Another aspect of the emergency feedwater system performance approved by the staff during theoperating license review was the controls and instrumentation for the system. The block valves forthe system which were closed in the TMI-2 accident
and prevented the delivery of water to the steam
generators have no automatic control. The overall
emergency feedwater system itself is not actuatedor controlled by the safety features actuation system. Actuation of the system was designed to occur on loss of main feedwater pumps, loss of all four
reactor coolant pumps, loss of power, or by manual
operation. Steam generator level was designed tobe controlled by the integrated control systemthrough throttling of the diaphragm operated emergency feedwater flow valves.
The staff's review and approval as reported in
the Safety Evaluation Report did not extend to verifi cation of Met Ed's assurance that the manuallycontrolled block valves in the emergency feedwater

10 0

flow lines would be open when flow was required.
However, the plant technical specifications did havethe primary responsibility of the STS group, which iscomposed of technical specialists working within the
Division of Operating Reactors. The licensing project manager within the Division of Project Management retains overall responsibility for completion of
the project review, but in the preparation of technical specifications, the project manager interacts
with the STS group within DOR rather than directlywith the technical review specialists within the Division of Systems Safety. The STS group, however,appoints one person within that group to be responsible for preparing the specifications and coordinati ng the efforts of the various technical specialists involved. A "proof and review" copy of the technicalspecifications is circulated to all review organizations and comments are solicited, but formal, documented concurrence is not required. Consequently,
last minute changes in technical specifications, justprior to license issuance, involve a significantly
higher risk of error. Such errors did occur in the
TMI-2 technical specifications, as described in an
earlier section entitled "Onsite Radiological Protecti on.

requirements on the "operability" of the emergency
feedwater flow paths. 76 The NRC has since foundthat Met Ed violated these requirements 77
regardingthe emergency feedwater isolation valves.
Technical Specification

The technical specifications which are incorporated in an operating license are based on the requirements of 10 C.F.R. Part 50.36. They are generally developed in parallel with the staff's safety review effort leading to the issuance of the staff's
Safety Evaluation Report. Because the as-built
condition of equipment is often important to the final
selection of safety limits and limiting control settings,
the final work on establishing the technical specifications is usually done in the last year before issuance of an operating license. In the case of TMI2, work started with the staff's transmittal to Met Edof a set of standard technical specifications for
B&W reactors in fate 1975. Over the next 2 years
an interchange of correspondence and several
meetings with the staff yielded the final set of
specifications that became Appendix A to Operating
License No. DPR-73 for TMI-2.
Technical specifications standardized in format
and content were developed several years ago foreach of the light-water reactor nuclear steam system suppliers. In October 1974, the D.C. Cook Station, Unit 1 was the first plant licensed utilizing thestandard technical specifications. Since that time all
facility operating licenses issued have incorporated
standardized technical specifications. These licensees have included three B&W reactors-Crystal
River Unit 3, Davis Besse Unit 1, and TMI-2.
Standard Review Plan section 16.0 gives a general statement concerning the intent to use standardized technical specifications that meet the requirements of 10 C.F.R. 50.36, and briefly statesthat "generic standard technical specifications" havebeen developed but are subject to revision and thatthe latest revision is available from the NRR. No details of the structure or content of the Standard
Technical Specifications (STS) are given within theStandard Review Plan nor are any acceptance criteria prescribed as in other Standard Review Plan
sections. As a result, the STS are a governing document unto themselves, existing as the most official available NRC staff interpretation of what isnecessary to comply with 10 C.F.R. 50.36.
Development of the detailed standard technicalspecifications during an operating license review isApplicant Technical Qualifications and Organization

The staff's review and evaluation of the Met Ed
organizational structure and of the technical qualifications of the organizational entity is documented in
the Safety Evaluation Report sections 13 and 14.
The regulatory criteria and authority for examinationof an applicant's technical qualifications is found in
10 C.F.R. 50.34(a)(9) and (b)(7). The regulatory criteria were further developed by additional information in October 1972 in the Regulatory Guide 1.70,"Standard Format and Content of Safety Analysis
Reports for Nuclear Power Plants," Revision 1, which
i n about two pages described the types of information that a prospective licensee should supply in an
applicant's Safety Analysis Report to "indicate generally how the applicant intends to conduct operations, and to assure that the licensee will maintain atechnically competent and safety-oriented staff."
No specific requirements are cited.
The Standard Review Plan sections 13.1.1, 13.1.2,
and 13.1.3 elaborate on what the acceptance criteria
might be, but does so with reference to WASH-1130
and ANSI N18.1-1971, indicating that those standards
are "generally acceptable" or contain provisions thatthe applicant "should meet or exceed." While theStandard Review Plan was not formally required for
the TMI-2 review, the staff's review and evaluationi n the Safety Evaluation Report indicated that ANSI
N18.1-1971 was complied with regarding selection

101and training of personnel. The staff declared in the
Safety Evaluation Report in October 1976 that theoverall organization structure was "satisfactory toprovide an acceptable operating staff," and that theapplicant had "the necessary resources to provide
offsite technical support for the operation of the facility." In accordance with the staff's general practice, there was no reported evaluation by the staff ofthe management plans or controls to effectively utilize the offsite technical resources when needed.
The Advisory Committee on Reactor Safeguards'
review in October 1976 resulted in an explicit, narrowly drawn comment by the committee:

evaluated by appropriate management officials, thelicensing staff is generally unaware of the more recent criteria and requirements so that implementation is largely an ad hoc activity that is not yet ensured on any given project.

Combustible Gas Control

It is well established that the TMI-2 plant systems
designed to cope with free hydrogen inside containment were inadequate during the course of the accident. Met Ed provided a thermal recombiner located outside the containment and attached to thecontainment by 4-inch piping. This system wasdesigned to circulate containment atmospherethrough the recombiner at about 60 standard cubicfeet per minute (the containment free volume isabout 2 million standard cubic feet) and to maintainthe containment hydrogen concentration below 4%hydrogen by volume.
The system design was based on hydrogen generation rates far lower than were experienced in the
TMI-2 accident, and in particular for less total hydrogen evolving from the reaction between steam
and the zirconium alloy cladding on the fuel rods inthe reactor core. The staff's licensing criteria effective in September 1976 were based on Regulatory
Guide 1.7, Revision 1, which referenced the General
Design Criteria and other appropriate sections of 10
C.F.R. Part 50, and led to staff approval of Met Ed's
design basis hydrogen generation predictions. 82
These predicted conditions were simply not
representative of the much greater amount of hydrogen produced in the first several hours of theTMI-2 accident, because of the extensive coredamage and zirconium-oxygen reaction of what is
now thought to be over 50% of the fuel cladding.
As a result of the large amount of hydrogen generated and released to the containment volume, a
rapid pressure rise, now thought to be due to a rapid hydrogen burn, occurred approximately 9 hours
and 50 minutes after the accident. 83 Since the accident, the NRC has recognized 84 the need toreconsider the design bases with respect to hydrogen production and control.

The management organization proposed by the Applicants to delineate the safety related responsibilities of the offsite and onsite personnel of the Three
Mile Island Station left open questions as to how
these responsibilities are to be discharged during
normal working hours and during evening, night,
and weekend shifts. This matter should be
resolved to the satisfaction of the NRC Staff.

This comment developed from information
brought up by the staff at the full ACRS meeting of
October 15, 1976. 78 Met Ed had submitted new organization charts in September 1976 which caused
the staff's Quality Assurance Branch reviewers to
be concerned about the priority given to allocationsof technical support personnel assigned to support
both TMI units at the site. Organization charts submitted in September 1976 showed the same technical support groups reporting to both unit supervisors simultaneously. Following the ACRS meeting,additional questions were asked of Met Ed. 79 The
concerns that surfaced at the October 1976 ACRS
meeting were resolved to the staff's satisfaction 80
by Amendment Nos. 52, 54, and 55 to the FSAR
and the resolution was reported in Supplement No.
2 to the Safety Evaluation Report, which was issued
in February 1978. The discussion in that supplement did not explicitly address the concerns expressed in the ACRS letter of October 26, 1976.
It should be noted that the ACRS comment discussed above was the only critical result of thecommittee's review of the Met Ed organization andtechnical qualifications, despite a wide ranging discussion of that subject at the full committee meeting. The NRC staff has recognized the inadequacyof its review process in this area for some years, as
shown by the exhibits in the Allenspach deposition, 81 but has not given the matter sufficient priority
to accomplish systematized improvement in the process from approximately 1974 to this date. (Technical qualifications as treated in the licensing process
are further discussed in Section I.A.3.d of this report.) While changes have been designed andQuality Assurance

I n the Safety Evaluation Report of September
1976, the staff found that:[T]he applicant has described an acceptable Quality Assurance organization which has sufficient authority and independence to permit effective implementation of their Quality Assurance program
without undue influence from costs and schedules.

10 2

We therefore conclude that the Quality Assurance
program is acceptable for control of the qualityrelated activities during the operational phase of theThree Mile Island Nuclear Station, Unit 2.

FSAR and the plant technical specifications. Thei mplementation of these programs through plant
operating procedures was left to IE. Thus, any deficiencies in quality assurance as practiced by Met
Ed were not likely to be discovered and were notdiscovered by NRR in the licensing process leading
to an operating license issuance. However, thepoint is not merely that had the condensate polishi ng system, or the pressurizer relief valve, or thevarious emergency procedures been engineered
and checked to higher quality standards, the TMI-2
accident would not have occurred. The existing QA
program must be expanded within NRR and effectively coordinated with the NRC inspection entities
to assure that an applicant is initially qualified andremains qualified to hold an operating license.

The staff's review was reported to be based on
the criteria of Appendix B to 10 C.F.R. 50 and anumber of regulatory "guidance" documents, includi ng:• WASH-1284:

Guidance on Quality Assurance
Requirements During the Operations Phase of
Nuclear Power Plants• WASH-1309: Guidance on Quality Assurance
Requirements During the Construction Phase of
Nuclear Power Plants• WASH-1283: Guidance on Quality Assurance
Requirements During the Design and Procurement Phase of Nuclear Power Plants

Pressurizer and Pressurizer Controls

I n addition, the Safety Evaluation Report stated that
Met Ed's demonstrated capability to implement satisfactorily the QA program on TMI-1 was further assurance that it could and would carry out the QA
program for TMI-2 satisfactorily.
The NRR is assigned the responsibility for determining that an applicant has adequate QA programplans and the organizational structure necessary to
carry out those programs. The office of IE has the
responsibility to evaluate and report on theapplicant's implementation of the program. The interface between these offices is another area inwhich good interoffice working relationships,
comprehensively designed and implemented NRC
procedures, and, above all, dedicated and determined NRC management is critical to theCommission's mandated objective of ensuring thatan applicant executes an adequate quality program.
Met Ed's program implementation was periodicallychecked by field inspections from the time of construction permit grant in 1969. However, as has
been noted by other reviewers, 85 and described inother sections of this report, both the NRC and its
predecessor, the AEC, have focused quality assurance on those portions of the plant considered"safety-related" and have ignored, or at least accorded much less significance to, the interactions of
nonsafety systems and nonsafety-related procedures, controls, and organizations with activities
clearly important to nuclear safety objectives.
(Further discussion of the meaning and applicationof the term "safety-related" is found in Section
I.A.3.b of this report.)
The regulatory staff's licensing responsibility, asdischarged totally within NRR, was focused essentially only on the Met Ed descriptions of its programs and organization as presented within theThis area of technical review provides an example of the lack of mutual understanding on the partof the NRC staff and the applicant concerning which
systems are important to plant safety and which
systems should be required to meet NRC standards
such as redundancy, diversity, the single failure criteria, and seismic load resistance. In its final approval of the TMI-2 design, the staff considered thematter of pressurizer control only to the extent
necessary to say that detailed schematic drawingsof the control circuitry had been reviewed. 86 No
criteria or conclusions were reported.
I n discussing the systems required for safe shutdown, Met Ed stated that pressurizer controls wererequired to ensure the capability of controlling reactor coolant pressure. 87 Perhaps significantly, Met Ed
did not consider the pressurizer heaters to be amember of the group called pressurizer controls,
because in this context Met Ed described only thespray valve control and the relief valve control. Because the controls are described with those othersystems required for safe shutdown, it may nothave been considered that the pressurizer heaters
would be needed during a process which should require only excess heat removal. Achievement of"safe shutdown" (reactor 1% subcritical, systempressure and temperature within technical specifications) was defined as a separate and apparently
l esser safety requirement than the reactor shutdown
achieved completely automatically by the reactor
protection system designed to meet the full"safety-related" criteria.
The Met Ed justification for the "safe shutdown"
system controls not being designed to full "safetyrelated" electrical criteria (IEEE Standard 279 requirements) was that the "safe shutdown" systems
1 03

are not protection systems like the reactor protection system (RPS) or the safety features actuation
system (SFAS). In this case, the line between
safety-related and nonsafety-related was drawn by
Met Ed at the boundaries of the RPS and SFAS
systems, and that distinction was accepted by thestaff. The TMI-2 event and studies following it haveshown that more sophisticated analyses of the needfor the pressurizer control system during expectedtransients, particularly those involving loss of offsite
power, are necessary. The licensing processduring the TMI-2 operating license review did notrecognize the need for the features now seennecessary, because the accident and transient assumptions evaluated simply did not reveal the needfor systems and controls other than those provided
by the reactor protection system and the engineered safety features actuation system.

The Process

1. Regulatory stability, in terms of organizational
control of the development and implementation of
new or modified requirements, has not beenachieved through the activities of the Regulatory
Requirements Review Committee.
2. The process does not adequately control theneed and justification for backfitting in accordance with 10 C.F.R. 50.109.
3. Coordination is lacking between the Division of
Operating Reactors and the Division of ProjectManagement in the critical period between
operating license issuance and transfer of the
project to the Division of Operating Reactors.
4. The public hearing process does not reveal or
explore the merits of much of the safety review
that is resolved between staff and applicant prior
to the hearing.

f. Findings and Recommendations

TMI-2 Review

Findings

1. The staff technical management failed to effectprompt (several months) resolution of the matterof appropriate emergency core cooling system
cut-off by an operator. The matter was raised asa generic issue in November 1976 by a dissenting
staff member, and surfaced again in Davis Besse
and other B&W plant transients in 1977 and 1978,
events which occurred either during the operati ng license review for TMI-2 or prior to the TMI-2
accident.
2. The staff did not respond to licensee's change inemergency plan after the operating license wasissued.
3. An operating license was issued on February 8,
1978 without the documented concurrence of thestaff responsible for technical specifications.
4. The operating license issued contained an error
in technical specifications that gave the licensee
an exemption from periodic testing of the capability of carbon filters in the auxiliary building.
5. The TMI-2 review, with a few exceptions, was inaccord with staff practice during the period April
1974 through September 1976.
6. Met Ed did not report on the safety significanceof equipment modification, after operating license
i ssuance, that resulted in continuous airflow
through carbon filters during normal operation instead of using them only postaccident. The
result was "poisoning" of filter carbon before it
was needed after the accident.

Design Basis

1. Safety objectives in the General Design Criteria
and other Title 10 regulations are too subjective
and imprecise to be effectively applied by engineers and scientists.
2. The standard format and content of Safety
Analysis Reports (Regulatory Guide 1.70) and theStandard Review Plan identify and structure a review which is inadequate in depth to prevent or
mitigate the consequences of a TMI-2-type accident.
3. The distinction in the review process between
safety-related and nonsafety-related equipment
or systems led to the staff's ignorance of the importance of malfunctions in certain "nonsafety
equipment."
4. Operator training, plant emergency operatingprocedures, control room design, applicant
technical qualifications, plant technical specifications, and quality assurance are areas for which
there are inadequate regulatory requirements oran inadequate management of the review process, or both.
5. The continuous increase in the number and costof regulatory requirements, applied without aclearly discernible technical rationale, has frustrated the industry, leading to an unsafe attitude
that "we'll give NRC what they ask for and not
one bit more."

10 4

staged, controlled process that provides for holdi ng plant designs standard over significant
periods of time.
5. An organizational element charged with continui ng responsibility to carry out recommendations
2, 3, and 4 above should be established.
6. The existing design basis accident concept
should be enlarged to a greater defense-indepth, to include sequences based on assumptions of at least one random failure, an additional
equipment unavailability due to a maintenancefault, and one human error in operation.
7. The hearing process should be modified either toi ncrease the technical content of the deliberations for the public benefit, or alternatively, andalso for the public benefit, to eliminate an essentially wasteful expenditure of public resources.
8. The comprehensive analysis and application ofoperating plant experience to the development of
new or modified regulatory requirements should
be assured.
9. An NRC internal Quality Assurance Program
should be established to ensure that the licensing
process is conducted in accordance with Commission approved standards.
10.The Standard Review Plan should be expanded
and developed in areas of operator training, plant
emergency operating procedures, control roomdesign, applicant technical qualifications, planttechnical specifications, and quality assurance.
Similarly, actions should be taken to ascertainthat the licensing organization is adequate to execute the expanded review.

7. B&W consistently told staff and ACRS that reactor vessel water level instrumentation was notnecessary. The staff and ACRS response, during
the TMI-2 review, was acquiescence, if notagreement.
8. The staff failed to implement Regulatory Guide
1.101 on emergency planning on Met Ed, which
had been declared by the Regulatory Requirements Review Committee to be a backfit measure.
Recommendations
1. Rational risk objectives should be establishedand approved by Congress. NRC must present
these objectives to the regulated industry and the
public through a rational policy that will generate
acceptance, respect, and cooperation from allparties.
2. Current requirements should be reevaluated usi ng the best available risk assessment techniques, with the purpose of meeting specific risk
objectives. New or modified requirements should
be expressed in the Standard Review Plan as theminimum acceptance criteria required for publichealth and safety at a given time.
3. An explicit rationale, which is as quantitative andobjective as possible, should be established forthe evaluation of proposed new safety requirements against the criteria "substantial additional
protection required for public health and safety."
4. New requirements should be implemented in a

105

REFERENCES AND NOTES
16 NRC 1185 (1977), included in Appendix 1.7.
2
Hearings Before the Joint Committee on Atomic
Energy, U.S. Gong., 1st Sess. (April 4, 6, and 20, and May
3,1967) at 303-307.
3
P.A. Morris and S.H. Hanauer, "Technical Safety
I ssues for Large Nuclear Power Plants," Fourth United
Nations International Conference on the Peaceful Uses ofAtomic Energy, at 207, September 1971, Geneva.See
Exhibit 1044, Hanauer dep.

Letter from W.T. Gunn, GPU Service Corporation, to
USNRC Directorate of Regulatory Operations, Subject:
Submittal of Schedular Information (TMI-2), dated May 6,
1976.
22
Letter from K. Kniel, NRC, to Met Ed, dated May 12,
1976.
23
See Section I.A.3.c for further discussion of genericissues.
24
Memorandum from B. Rusche, NRC, to Division
Directors, "Revised Procedures for Documentation of
Deviations from the Standard Review Plan," January 31,
1977.
25
ACRS Subcommittee Meetings Transcripts (September 23-24, 1976) and the 198th General Meeting of
the ACRS Transcript (October 15,1976).
26
4 AEC at 283, November 12,1969.
27
See Petition for Intervention by Citizens for a Safe
Environment, of Harrisburg, Pennsylvania, and the York
Committee for a Safe Environment, of York, Pennsylvania,
June 18, 1974. These organizations were the Joint Intervenors. The petitions are on file in Licensing Docket No.
50-320.
28
6 NRC at 1201, 1203 (December 19, 1977).
296 NRC at 1201-1202.
3D6 NRC at 1206.
316 NRC at 1203.
32
8 NRC at 9,14, 25 (July 19,1978).
33
8 NRC at 23.
34
Letter from H. Brown, Office of International andState Programs, to E. Kline, Lieutenant Governor,
Pennsylvania, Subject: Radiological Emergency Response
Planning, dated May 9, 1975.
35
Letter from E. Kline to H. Brown, dated May 21,
1975.
36
Fourth Report by the House Committee on Government Operations, "Emergency Planning Around U.S.
Nuclear Powerplants: Nuclear Regulatory Commission
Oversight," 96th Gong., 1st Sess., dated August 8, 1979,at 31.
37
GAO Report No. EMD-78-110, dated March 30,
1979, at 42.
38
8 NRC at 25.
398 NRC at 48-49 and 295 (September 15,1978).
40
Memorandum from S. Varga, NRC, to Distribution
List, "Transfer of TMI-2 to DOR," September 19, 1978.
41
Note from V. Stello, Jr. to D. Vassallo, "Transfer of
TMI-2 to DOR," September 26, 1978.
42 Reid dep. at
9.
21

Memorandum from R. DeYoung, USAEC, to P. Morris,"RTM and TAR Status Report," April 2,1969.
5
Memorandum from V. Moore, USAEC, to S. Levine,"Reactor Technology Memorandum (First Draft) - OffSite Electric Power," February 28, 1968.
6
Memorandum from R. DeYoung, USAEC, to R. Boydand D. Skovholt, "Design Basis Criteria for Pressurized
Water Reactor Dry Containments, January 3, 1969,"
February 19,1969.
7
Between April 1968 and May 1969, Jersey Central
Power & Light Company took full responsibility for thedesign and construction of the facility, and the AEC
licensing staff dealt exclusively with JCPL. By Amendment 9 to the Preliminary Safety Analysis Report (May 7,1969) the responsibility for design and construction wastransferred to the Metropolitan Edison Company. The
Pennsylvania Electric Company's Purchase of a 25%
ownership interest in 1971 did not change this responsibility, which continued to be that of Metropolitan Edison.
8
NRC, "Report to ACRS-Three Mile Island Unit 2,"
June 20,1969.
9
Memorandum from R. Tedesco, USAEC, to P. Morris,"Report to ACRS on Three Mile Island," June 16, 1969.
10
Memorandum from R. Powell, USAEC, to R. Boyd,"ACRS Subcommittee Meeting for Three Mile Island
Nuclear Power Plant Unit 2," July 17, 1969.
'"Letter from S. Hanauer, USAEC, to G. Seaborg, Subject: Report on Three Mile Island Nuclear Station Unit 2,
dated July 17, 1969.
12 Safety Evaluation by the Division of Reactor Licensing, U.S. Atomic Energy Commission in the Matter ofMetropolitan Edison Company and Jersey Central Powerand Light Company, Three Mile Island Nuclear Station
Unit 2, Dauphin County, Pennsylvania, September 5,
1969.
13
NRC, Federal Register, Vol. 34, No. 13708,1969.
14 Memorandum from H. Price, USAEC, to Commissioners Seaborg, et al., "Issuance of Safety Guides," June 25,
1970.
15
U.S. Atomic Energy Commission Information Reportto Commissioners, "Regulatory Requirements Review
Committee," SECY-R-74-132, March 5, 1974.
16 Memorandum from E. Case, USAEC, to L.V. Gossick,"Regulatory Requirements Review Committee Meetings,"
June28, 1974 (Meeting No. 4) and September 19,1974.
17
Washburn
dep. at 9, 10.
18Note from H. Berkow, NRC, to Chairman Hendrie,"Schedule Performance Evaluation," January 31,1979.
4

19

43

/d. at 15.

AEC Directorate of Licensing, "Final Environmental
Statement Related to Operation of TMI Nuclear Station,
Units 1 and 2," Section XI, December 1972.
44

45
The results of this review are described in Chapter
15 of the staff's "Safety Evaluation Report, related tooperation of Three Mile Island Station, Unit 2," NUREG0107, September 1976, and Supplement 1, undated.

Silver dep. at 65 (Pres. Com.).

46

Memorandum from H. Silver to Technical Review
Branch Chiefs, "TMI-2 SER Open Items," March 16, 1976.

AEC, "Final Environmental Statement, Three Mile
Island Station, Unit 2," December 1972.

20

10 6

AEC, "Final Supplement to the Final Environmental
Statement," December 1976.
48
1 0 C.F.R. Part 50, Proposed Annex to Appendix D,"Discussion of Accidents in Applicants' Environmental
Reports: Assumptions," Federal Register, 36 FR 22851,
and Statement of Consideration, 39 FR 26279.
49
Babcock & Wilcox Company, "ECCS Analysis of
B&W's 177-FA Lowered Loop NSS," BAW-10103, Revision 3, at C-7, July 15, 1977.
50
Transcript of TMI-2 Operating License Hearing (May18, 1977) at 1322.
51
NRC, "Report of the Advisory Committee on Reactor
Safeguards on Selected Safety Issues Related to LightWater
Reactors," Issue No. 4, December 12,1976.
52
NRC, "Staff Discussion of Fifteen Technical Issues
Listed in Attachment to November 3, 1976 memorandum
from Director, NRR, to NRR Staff," NUREG-0138,
November
1976.
53
Memorandum from N. Mosely to V. Stello, "Emergency Operating Procedures Governing S1S Reset at
Operating PWR's-Memorandum dated June 28, 1978,"March 19, 1979.

sioner Ahearne, "Instrumentation to Follow the Course ofan Accident," September 4, 1979.
87
Report to Congress by the Comptroller General of
the U.S., "Areas Around Nuclear Facilities Should Be
Better Prepared for Radiological Emergencies," GAO
Report No. EMD-78-110, at 14,16; March 30,1979.
68 Hearings Before the Subcommittee on Nuclear
Regulation of the Committee on Environment and Public
Works, U.S. Senate, 96th Cong., 1st Sess., (April 10, 23,
and 30, 1979) Part I at 200-202.
69 Memorandum from E.G. Case, NRC, to L.V. Gossick,"Regulatory Requirements Review Committee Meeting No.
34, August 15,1975," August 22,1975.
70
Memorandum from G. Knighton, NRC, to R. Reid,"Three Mile Island Site Revised Emergency Plan,"November 1, 1978.
71
NRC, "Safety Evaluation Report for TMI-2 at the
Operating License Stage," NUREG-0107, Sections 1.6,
7.4.1,10.5, September 1976.
72
Letter from K. Kniel, NRC, to R.C. Arnold, Met Ed,
Subject: Further Requirements for Licensing of Three Mile
Island, Unit 2, dated August 21,1974.
73
Letter from D. Moeller, ACRS, to Chairman Rowden,
Subject: Report on Three Mile Island Nuclear Station, Unit
2, dated October 22,1976.
74
NRC, "Safety Evaluation Report Supplement No. 2,"
NUREG-0107, Sections 15.2.2, 15.3.1, 15.3.2, February
1978.
NRC, "TMI-2 Operating License No. DPR-73,"
February
8,1978.
76
NRC, "TMI-2 Operating License No. DPR-73," atAppendix A; Technical Specifications at 3/4.7-4, 5.
77Letter from V. Stello, NRC, to R.C. Arnold, Met Ed,
Subject: Investigation Report Number 50-320/79-10,
dated October 25, 1979.
78
Allenspach dep. at 73 and Exhibit 1062 at 345-350.
79
Memorandum from C.J. Heltemes, NRC, to S. Varga,"Three Mile Island Unit 2, Conduct of Operations,"
December2, 1976.
80
Memorandum from D.J. Skovholt, NRC, to D.B. Vassallo, "Three Mile Island, Unit No. 2 Safety Evaluation
Report, Conduct of Operations," May 6,1977.
81
Allenspach dep. at 73 and Exhibit 1062 at 345-350.
82
Met Ed, "Final Safety Analysis Report, Three MileI sland Nuclear Station-Unit 2," Vol. 4, Figure 6.2-34,
Amendment 14.
83
NRC, "Investigation into the March 28, 1979, Three
Mile Island Accident by Office of Inspection and Enforcement," NUREG-0600, at 1-4-47, August 1979.
84
NRC, "TMI-2 Lessons Learned Task Force Status
Report and Short-Term Recommendations," NUREG0578, at A-23, July 1979.
85
The President's Commission on the Accident atThree Mile Island, "Technical Staff Analysis Report Summary," at 18-1, October 31, 1979.
86
NRC, "TMI-2 Safety Evaluation Report," NUREG0107, Section 7-4, October 1976.
87
Met Ed, "Final Safety Analysis Report, Three Mile
Island Nuclear Station-Unit 2," Vol. 5, Section 7.4.1.1.6,
Amendment
58.
68
NRC, "TMI-2 Lessons Learned Task Force Status
Report and Short-Term Recommendations," NUREG0578, at A-1, July 1979.

47

54

NRC, "TMI-2 Lessons Learned Task Force Status
Report and Short-Term Recommendations," NUREG0578, at 18, July 1979.
55
Memorandum from R. Boyd to E. Case, "Proposed
Technical
Activity," March 3,1978.
56
NRC, "Investigation into the March 28, 1979, Three
Mile Island Accident by Office of Inspection and Enforcement,"
NUREG 0600, at 11-1-28, August 1979.
57
Appendix A to Operating License No. DPR-73,
February 8, 1978, at 3/4-40.
58
NRC, "Staff Discussion of Twelve Additional Technical Issues Raised by Responses to November 3, 1976
Memorandum from Director, NRR, to NRR Staff,"
NUREG-0153, December 1976.
59
Memorandum from B. Rusche, NRC, to R. Boyd, etal., "Revised Procedure for Documentation of Deviations
from the Standard Review Plan," January 31,1977.
60
Transcript of the 208th General Meeting of the
ACRS (August 11, 1977) at 98-106.

Letter from M. Bender, ACRS, to Chairman Hendrie,
Subject: Report on Babcock-205 Standard Nuclear
Steam System, dated August 18, 1977, Appendix D in
" Safety Evaluation Report Related to the Preliminary
Design of the BSAR-205 Standard Design," NUREG=
0433, Docket STN 50-561, May 1978.
81

62

Letter from M. Carbon, ACRS, to M. Rogovin,
NRC/SIG, Subject: Significant Recommendations by
ACRS in 14 Specific Areas on Non-B&W Plants, dated
July 25,1979.
63Memorandum from R. Minogue, NRC, to H. Denton,"Instrumentation to Follow the Course of an Accident," at2, August 17, 1979.

84
NRC, "NRC Program for the Resolution of GenericIssues Related to Nuclear Power Plants," NUREG-0410,
January 1978.
65

Memorandum from R. DeYoung, NRC, to R.J. Mattson, R.S. Boyd, V. Stello, E.G. Case, "Draft Report ofCompletion of Generic Activity A-34," March 28,1979.
66

Memorandum from H. Denton, NRC, to Commis-

10 7

2. OPERATING HISTORY OF THREE MILEI SLAND NUCLEAR STATION

Date
1/23/75

Three Mile Island Unit 1

3/30/75

An operating license for TMI-1 was issued on
April 9, 1974. Initial criticality was achieved June 5,
1974; initial electrical power generation occurred onJune 9, and commercial operation was declared on
September 2, 1974. Based on the review of License
Event Reports and Monthly Operating Reports,
TMI-1 experienced at least 10 reactor trips, instances in which all control rods are inserted simultaneously into the reactor core stopping the nuclear
reaction, during the first year of operation. The foll owing is a yearly summary of the operating history
of TMI-1.

4/5/75
5/9/75
5/22/75
5/25/75

6/18/75

June 5, 1974 Through December 31, 1974

6/25/75

After the unit began commercial operation there
were only two outages. The unit operated near fullpower continuously during September through December. The following lists contain the occurrences
reported during the period of June to December
1974.
Date
Event
7/12/74 Reactor trip due to faulty relays on turbine generator. Duration, 8 hours.
7/13/74 Reactor trip due to feedwater flow oscillation. Duration, 8.1 hours.
7/14/74 Reactor trip due to technician error.
Duration, 30.7 hours.
8/3/74
Reactor trip due to operational error.
Duration, 11.6 hours.
8/13/74 Reactor trip scheduled as part of test
program. Duration, 244.3 hours.
8/26/74 Manual shutdown to repair steam andfeedwater leaks. Duration, 47.8 hours.
3/30/74 Reactor trip due to turbine trip andoperator error. Duration, 29.7 hours.
10/20/74 Scheduled outage to repair leaking pressurizer relief valves. Duration, 248.5
hours.
11/7/74
Manual reactor shutdown to repair control rod drive motor. Duration, 97 hours.

7/27/75
9/7/75
9/26/75
10/16/75
11/12/75

12/16/75

Event
Human error resulting in turbine-reactor
trip. Duration, 40 hours.
Faulty relay resulting in turbine-reactor
trip. Duration, 14 hours.
Rod drop and manual shutdown resulting
from a faulty cable connector. Duration,
214 hours.
I nstrumentation
malfunction l ed toturbine-reactor trip. Duration, 9 hours.
Power reduction due to problems in anelectrical power transformer. Duration,
16 hours.
Motor shaft sheared on decay heatpump. Unit manually shut down forrepair of pump and scheduled control
rod interchange. Duration, 421 hours.
Instrument error led to load reduction
and reactor trip. Duration, 20 hours.
Reactor trip due to rod drop resulting
from an electrical connector problem.
Duration, 27 hours.
Power reduction for repair of feedwater
pumps. Duration, approximately 4 days.
One day power reduction to verify vibration of main reactor coolant pump.
Manual shutdown to repair coolant
pump. Duration, 266 hours.
Manual shutdown to repair control rod
drive stator. Duration, 94.4 hours.
Manual shutdown to repair control rod
drive mechanism for the second time.
The outage was extended to repair turbine control valve. Duration, 303 hours.
Manual shutdown to repair makeup
valve. Duration, 104 hours.

January 1, 1976 Through December 31, 1976

The major outage during 1976 was for scheduledrefueling and maintenance, and was extended for
repairs to other equipment. During calendar year
1976 there were four outages; one was because ofoperator error and the others equipment failure. As
a result, the unit availability factor was reduced to65.4% and the unit capacity factor to 60.3%.
Date
Event
1/16/76
Manual shutdown of the reactor to repair
control rod drive mechanism. Duration,
46 hours.
2/20/76 Refueling. Duration, 1,532 hours.
3/3/76
Refueling outage extended because ofproblems with fuel handling equipment.
Duration, 48 hours.

January 1, 1975 Through December 31, 1975

There were 13 forced and 3 scheduled outages in
1975. Of these 16 outages, 11 were caused byequipment failure, 3 were performed for maintenance, and 2 resulted from operational errors. The
TMI-1 unit had a favorable unit availability factor of
82.2% and capacity factor 2 of 77.3%.
1 08

3/15/76
5/27/76
11/5/76Three Mile Island Unit 2

Extended outage to remove damaged
surveillance specimen holder tubes.
Duration, 720 hours.
Reactor trip due to operator error.
Duration, 7 hours.
Manual shutdown for scheduled repair ofdecay heat valve and pipe in riverwater
system. Duration, 683 hours.

The NRC issued an operating license for TMI-2
on February 8, 1978. The license identified anumber of preoperational tests, startup tests andother items to be completed by Met Ed within specified time frames. As a result of a mechanical failure
i n one of the reactor coolant pumps, the initial testi ng program was performed with one pump out ofservice for the period March 14 through May 17,
1978. The technical specifications permitted threepump operation, however, and the initial criticality
was achieved on March 28, 1978, approximately 2months sooner than if four pumps had been used.
From February 1978 to March 1979, TMI-2 experienced at least 20 reactor trips, approximately
one-third of which originated in the condensate andfeedwater system. In addition, four transientsresulted in the actuation of the ECCS high pressure
injection system. Table 1-6 contains a chronology of
the TMI-2 operating history.
The major outage for TMI-2 was necessary inorder to replace all of the main steam safety valves.
These valves were the first of a kind design andfailed to reset after lifting. This outage lasted about
5 months, beginning in April 1978. The secondl ongest outage resulted from rupture of the atmospheric dump valve bellows and lasted approximately
2 weeks during January 1979.

January 1, 1977 Through December 31, 1977

The second refueling and maintenance outage
took place during 2 months beginning March 18,
1977. Because the unit operated uninterrupted for 6
months, the unit availability factor increased to80.9% and capacity factor increased to 76.2%.
Date
Event
2/5/77
Power reduction to repair turbine test
tubing. Duration, 7 hours.
3/18/77
Refueling and maintenance. Duration,
1,394 hours.
9/16/77
Initial outage was by manual shutdown
to correct problems in the demineralizer
in order to reduce conductivity in thesecondary fluid system. The outage
was extended to repair reactor coolant
pump motor and generator ground. Total outage, 261 hours.
11/14/77 Reactor trip due to failure of integrated
control system.

Comparisons to Other Plants

Table 1-7 presents a comparison with otherplants by number of Licensee Event Reports (LERs)
filed with the NRC for the year of operation after the
license was issued. This table provides some qualitative correlations between TMI-2 and other B&W
plants and other two unit sites using equipment supplied by other pressurized-water-reactor vendors.
I n addition, a comparison of the LERs on PWRs nuclear steam suppliers for 1975 through 1978 is provided in Table 1-7. The comparisons, although notdefinitive with respect to underlying causes, indicatethat the performance for TMI-2 and other B&W
plants is average for PWR vendors. The director of
IE Region I office considered Met Ed's performanceas average compared with other licensees in his region. 3
During its year of operation, TMI-2 had four
events which resulted in actuation of the emergency
core cooling high pressure injection system and thei njection of borated water into the primary coolant
system. The ACRS task force evaluating Licensee
4
Event Reports reported 40 inadvertent ECCS actuations in PWRs from 1976 through 1978. Actua-

January 1, 1978 Through December 31, 1978

The third refueling and maintenance outage for
TMI-1 began March 18, 1978, and lasted 2 months.
The year reflected a good operating history, compared to the previous year, and resulted in slight increases in the percentages of unit availability to
85.1% and capacity to 79.1%.
Date
Event
3/8/78
Refueling. Duration, 1,086 hours.
9/22/78 Manual shutdown to repair seal fracture
on reactor coolant pump. Duration, 214
hours.
11/15/78 Power reduction to correct electricalproblems on turbine control system.
Duration, 14 hours.
January 1, 1979 Through February 17, 1979

Full power operation was maintained until shutdown for refueling on February 17, 1979. TMI-1 wason hot-shutdown status at the time of the TMI-2 accident.
1 09

TABLE 1-6. Chronology of TMI-2 operating experienceDate

2/8/78Operating License issued.

3/28/78

I nitial criticality.

3/14/78
3/29/78
4/1/78
4/18/78

4/19/78
4/20/78
4/23/78

9/18/78
9/19/78

9/20/78

9/21/78
9/22/78
10/5/78
1 0/13/78

Event

Began three-pump operations. Lost one pump due to mechanical failure.
Reactor trip. Pressurizer relief valve open. ECCS actuation. Shutdown (zero power) duration, 57.6 hours.

Reactor trip due to instrument failure indicating loss of second pump in coolant loop.
Duration, 182.9 hours.
Reactor trip due to noise spike. Duration, 7.6 hours.

Reactor trip due to loss of feedwater due to personnel error performing maintenance on
feedwater pumps. Duration, 7.9 hours.
Reactor trip due to spurious high flux spike. Duration, 6.0 hours.

Reactor trip caused by spurious signal. Five main steamline safety valves fail to close,
and the ECCS was actuated. Design error of the valves necessitated replacement of all
steamline safety valves, requiring shutdown until September 17, 1978. Metropolitan Edison removed orifice rods and installed retainers on burnable poison rods during thisoutage.
TMI-2 generated power for the first time.

Manual reactor trip. During test procedure of shutdown outside control room, feedwater
valve closed and reactor did not trip when turbine tripped. Duration, 6 hours.
Reactor trip due to loss of one main feedwater pump. Duration, 9.2 hours.

Reactor trip due to control problems with feedwater pump. Duration, 8 hours.

Manual reactor shutdown for scheduled testing of main steam safety valves. Duration, 92
hours.
Extended outage due to Conax connector problems on steam generator. Duration, 181
hours.
Hot standby for 4 hours to repair turbine generator.

1 0/14/78

Two reactor trips due to feedwater pump problems. Duration, 13.7 hours.

10/28/78

Manual reactor shutdown in order to repair turbine. Duration, 90.1 hours.

11/3/78

Reactor trip due to loss of feedwater. Personnel error resulted in loss of power to condensate polishing valve.

10/17/78
1 0/20/78
1 0/21/78
1 0/29/78

11/7/78
1 2/2/78

Reduced power for total of 7.7 hours due to problems in the main generator relay, which
prohibited synchronization with power grid.

During reactor shutdown a rachet trip of Group 5 control rods occurred. After trip, threerods were stuck at the 5% withdrawn positions.

Reactor trip due to loss of feedwater. Pressurizer level indicated below zero, and the
ECCS was actuated. Feedwater system was found to be contaminated with oil. Duration,
594.6 hours.
Reactor trip due to loss of feedwater pump. Duration, 1.7 hours.

11 0TABLE 1-6. Chronology of TMI-2 operating experience-Continued
Date

Event

12/2/78

Reactor trip during recovery from loss of feedwater. Duration, 4.8 hours.

1 2/16/78

Reactor trip due to mechanical failure in feedwater pump. Duration 146 hours.

1 2/2/78

12/28/78

1 2/30/78
1/2/79

1/5/79

1/14/79

1/15/79
1/31/79

Reactor trip due to personnel error resulting in excessive feedwater resulted in ECCS
actuation. Duration, 28.3 hours.
Manual reactor shutdown to repair a number of steam leaks.

Hot standby for 3 hours to repair steam leak in turbine. Unit achieved 80% power anddeclared in commercial operation at 11:00 p.m. Unit maintained 82% power after 6:30
a.m. on December 31, 1978, until second heater drain pump could be returned to service.
Turbine taken off line to repair hydraulic leak. Duration, 11.5 hours.

Rod drops due to blown fuse. Automatic power reduction and then power escalation.

Reactor manual shutdown to repair leaking pressurizer instrumentation isolation valves.

During startup, reactor tripped due to loss of power to pressurizer. Outage extended to
repair atmospheric dump bellows and a number of pressurizer instrumentation valves.
Duration, 425.9 hours.
Unit returned to service.

2/6/79Feedwater pump trips twice with automatic power runback to 55%.

3/6/79Turbine generator trip followed by reactor trip. Duration, 16.5 hours.

2/10/79
3/7/79Reactor maintained at 13% power during 13.2 hour outage to repair turbine leaks.
Unit operated near 97% power until loss of feedwater trip on March 28, 1979.

tions required by depressurization and other transients, which were not inadvertent, were not addressed.
A request to the NRR for information allowing acomparison of the number of TMI-2's safety injection events to those of other operating plants revealed that such information was not available andthat a two-man-month effort would be required toobtain such information. Consequently, no data
were provided, and the SIG was unable to make thiscomparison. This lack of operational information issignificant, demonstrating that a major deficiency in
NRC activities is the lack of a structured, systematicand coordinated process for collection, review, andevaluation of operational data. 5

Rod Positions-Rod Groups one through five were
fully withdrawn, groups six and seven were 95%
withdrawn, and group eight was 27% withdrawn.
Pressurizer-

Level-229 inches
Spray-Spray valve open
Heaters-Energized in manual control
Leakage-Through one of the safety valves(RC-RIA or RC-121B)
Header temperature-190°F.

The leakage noted above could have been
through pressurizer relief valve. The temperaturei ndication is on header from all three valves.
Primary Coolant Systems-

TMI-2 Plant Status on March 28, 19796

Loop A
Pressure-2165 psig
Flow-68.484 MPPH (Million Pounds
per Hour)Temperature-Hot Leg-606°F
Cold Leg-558°F

Operating Status

The plant status prior to 4:00 a.m. on March 28,
1979, was as follows:
Power Level-97.928% full power (872 MWe).
11 1

TABLE 1-7. Comparison of licensee events

Plant

Component
FailureDefective
Procedures

Design/Fabrication
Error

External
Cause

Other

Personnel
Error

Totals

3/28/78 03/28/79
3/28/78-03/28/79

9
13

1
5

3
14

0
0

5
10

4
10

22
52

1 2/01/76 - 12/01/77
1 2/01/76 12/01/77

43
67

8
1

4
6

1
1

38
14

14
12

1 08
1 01

03/10/78-03/10/79
03/10/78-03/10/79

22
39

5
5

8
19

0
1

12
21

17
28

64
113

01/01/78 - 01/01/79

54

33

12

24

30

117

-

1 46

24

01/01/78-01/01/79

1 00

21

25

8

45

56

255

Time Period

B& W

TMI-1
TMI-2

-

CE
Calvert Cliffs-1
Calvert Cliffs-2(11/76)`W

D. C. Cook-1
D. C. Cook-2
Two Unit Stes

TMI-1 (6/74)*
Calvert Cliffs 1(10/74)"
D.C. Cook 1(1/75)`

01/01/78 01/01/79*Represents date unit achieved criticality

17

16

8

69

42

298

TABLE 1-7. Comparison of licensee events-Continued

B&W Facilities-One-Year Period Immediately Following License Issuance

Plant

Arkansas 1
Crystal River
Davis Besse
Oconee 1
Oconee 2
Oconee 3
Rancho Seco
TMI-1
TMI-2

Time Period

Number of LERs per Operating Plant:
Babcock & Wilcox
Combustion Engr.
Westinghouse
All PWRs
All BWRs*

Component
Failure

1975

1976

46.7
( 6)*

30.3
( 6)

25.0
(17)

31.3
(19)

41.8
( 4)

32.3
(27)
43.9
(22)

4
34
51
11
7
12
9
27
13

1977

45.4
(8)

40.1
( 22)

39.2
( 23)

64.1
( 7)

33.6
( 30)

42.1
( 35)

52.6
(23)

52.8
( 25)

2
7
14
7
6
2
5
18
5

Design/Fabrication
Error
3
7
18
4
1
7
4
20
14

External
Cause
19
3
4
0
0
0
1
5
0

1978

23.7
( 6)

46.4
( 5)

Defective
Procedures

46.4
( 8)

42.6
( 39)
46.8
(25)

Numbers in parentheses represent number of operating plants. Some information from Reference 8.

Other
21
35
21
1
2
0
0
5
10

Personnel
Error
2
16
22
11
9
12
11
11
10

Totals
51
1 02
1 30
34
25
33
30
86
52

Loop B

Pressure-2148 psig
Flow-69.72 MPPH
Temperature-Hot Leg-606°F
Cold Leg-557°F
Activity-Beta/Gamma-0.3783 Ci/ml
Leakage-0.4 gpm
Letdown flow-70 pgm
Boron Concentration-1027 ppm
Reactor coolant makeup pump (MU-P-1B) was inservice providing makeup and reactor coolant pumpseal flows.
Secondary
Coolant System-

Loop Feedwater
Operating Level
Startup Level
Steam Pressure
Feedwater Temperature
Steam Temperature

Steam
Generator A

5.7459 MPPH
56%
158.8 inches
910 psig
462.7°F
595°F

Steam
Generator B

5.7003 MPPH
57.4%
163.4 inches
889.6 psig
462.7°F
594°F

Steam Generator Feedwater Pumps (FW-P-1A and
FW-P-1B) were in service, condensate pumps (COP-2A, CO-P-18) were in service.
Genera! Plant Parameters

Borated Storage Tank Level-55 feet
Borated Storage Tank Temperature-68°F
Reactor Building Pressure-0.1 psig
Reactor Building Temperature-124°F (average)
A
Core Flood Tanks
595
pressure (psig)
13
level (feet)isolation valves open

the station air system was interconnected. There
were at least two previous occasions during whichwater had contaminated the air system. 8
Another deficiency in the plant status at the timeof the accident was a wiring error in the control circuitry for the condensate pumps and the conden9
sate booster pumps. This error caused the condensate pump to trip when the condensate booster
pump tripped. The condensate pump trip resulted in
the feedwater pumps' trip.
Other deficiencies in the plant status relevant tothe accident have been described in detail previousl y and are identified here for completeness:
1.
2.
3.

Leaking pressurizes relief-safety valves 8
Leaks in the makeup and letdown systems 8
Lack of containment isolation actuation uponsafety injection signal10

Equipment Status
Table 1-8 contains a list of activities and connected systems between TMI-1 and TMI-2 on the day of
the accident. The extraction system was being
supplied by TMI-2 to TMI-1; demineralizer water was
being supplied by both units; and the condensate
return system was being supplied by TMI-1 to TMI2. Neither the shared activities nor the systems appear to have had any detrimental effect on the
TMI-2 accident. Table 1-9 lists the equipment which
was out of service on March 28, 1979. None ofthese outages violated the technical specifications
for limiting conditions for operation.

B
600
13

Findings
1.

Reactor Building Sump-On March 17, 1979, thesump pump had started seven times and had
discharged approximately 1,468 gallons.
The most relevant activity just prior to the accident was an effort to unclog the transfer line fromone of the condensate polishing vessels. This effort
had been going on for approximately 11 hours, andsupposedly had led to water entering the instrument
air line. The polisher valves closed and the condensate pump (CO-P-1A) tripped. Although the checkvalve between the condensate polisher and service
air system was frozen in the open position, the water still would not have had a path to the instrument
air system except that the instrument air and station
air systems were connected. Evidently, because
the instrument air system lacked adequate capacity,

2.

3.

4.
5.
6.

114

Based on the number of LERs, the performanceof TMI-2 and other B&W plants is averagecompared with other pressurized water reactor
vendors.
The director of IE Region 1 considered the performance of the Metropolitan Edison Company
to be average as compared with other licensees in his region.
TMI-1 reported fewer licensee events during thefirst year of operation than other two unit sites
supplied by other PWR vendors that wereselected for comparative purposes.
TMI-2 reported fewer licensee events during
the first year of operation than did TMI-1.
TMI-1 has operated since 1974 without significant operational problems.
NRC lacks a structural, systematic and coordinated process for collection, review, evaluationand feedback of operational data.

TABLE 1-8. Connections and shared activities between TMI-1 and 2
Shared Activities

Security-Common site protection force and protected area.

Fire Suppression Water System-Common system for both Unit 1 and Unit 2.
Radwaste, So/id-Radwaste solidification done in Unit 1.
I ndustrial Waste Treatment System

Paging System-Common page system.

230-kV Substation-Offsite power for both units provided via common 230-kV substation.
River Water Chlorinator-Common system to chlorinate each unit's control room.
Meteorological Tower-Common tower reading in each unit's control room.

River Water Discharge Canal-Common discharge to river from each unit's mechanical draft cooling
tower.
Primary Sampling Room-Common room for sampling Unit 1 and Unit 2 primary samples.

Connections

Extraction Steam System-Either unit can supply other unit with extraction heating.
Demineralized Water System-Supplied by Unit 1.

Condensate Return System-Condensate return connection if extraction steam is supplied.
Turbine Lube Oil Storage System-Common storage and makeup capability.

Radwaste Liquid System-Cross-connected to transfer liquids between the units.
I nstrument Air System-Not normally open.

' Domestic Water System-Supplied by Unit 1.

HVA C Fuel Handling Building- Common building, each unit's area with its own heating, ventilation
and air conditioning.

TABLE 1-9. Equipment out of service on March 27 and 28, 1979

1 5. Makeup Skid Acid Block and Bleed Valves(r8, 9 & 10)
1 6. Heater Drain Limit Switch (HD-LS-327) on
Heater Drain Tank (HG-T-1)
1 7. Main Steam Thermostat (MS-U-32B) on
Turbine Bypass Line
1 8. Reactor Coolant Hot Leg Drain (RC-U-4)

1. Chlorine Evaporator (CL-2-1)
2. Condensate Flow Transmitter (CO-FT-070)
3. Clearwell Tank (WR-T-2)
4. Mechanical Room Fan Coil Unit (AH-C-24)
5. Soil Exhaust Pre-filter (AH-F-27)

6. Feedwater Heater 3A Sight Glass
7. Temporary Sodium Hydroxide Pump (WT
Caustic Tank)
8. Heater Drain Pump B (HD-P-1B)
9. Reactor Building Normal Cooling (RB-21 A-2)

1 9. Fire Door Between Auxiliary and Fuel Storage
Buildings
20. Ammonia Pump A (AM-P-1A)
21. Breaker 24 (spare) 2-4V Vital Power Supply
22. Auxiliary Building Sump Tank (WDL-T-5)
23. Sodium Thiosulfate Tank (DH-T-3)

10. Heater Drain Valve (HD-V-65B)
11. Control Building Fan Coil Unit (AH-C-52B HTR)
1 2. Control Building Fan Coil Unit (AH-C-52D)
13. Evaporative Cooler (RB-L-183)

24. Makeup System Pressure Transmitter( MU-2-PT)

1 4. Mechanical Draft Cooling Tower Fan 2-3

115

REFERENCES AND NOTES
6'Availability factor is defined as:

Letter from J. Herbein, Met Ed, to M. Rogovin,
NRC/SIG, Subject: Response to Letter from Special
I nquiry Group (NTFTM 780626-01), dated June 26,1979.
T
I nterview of G. Lehmann (Interview No. TM-294).
8
NRC, "Staff Report on the Generic Assessment ofFeedwater Transients in Pressurized Water Reactors
Designed by the Babcock & Wilcox Company," NUREG0560, May 1979.
9lnterview of G. Lehmann (Interview No. TM-294) at
23.
10
Letter from J. Hendrie, NRC, to Chairman Kemeny,
Subject: President's Commission on the Accident atThree Mile Island (Response to Questions by the Commission), dated June 25,1979.

Hours generator on li ne x 100
Gross hours in report period
2

Capacity Factor is defined as:

Net electrical power generated x 100
Authorized net MWe (892 MWe) x gross hours in report period.

Grier dep. at 81.
NRC, "Review of Licensee Event Reports 1976-1978,"
Advisory Committee on Reactor Safeguards, NUREG0572, September 1979.
5
Memorandum from D. Davis, NRC, to L. Gossick,"Task Force Report on Operational Safety Data Analysis
and Evaluation," May 15, 1979.
3

4

11 6

construction phase. Most of these concerned thequality assurance area. Health physics was themost frequent noncompliance for TMI-1. A comparison of TMI enforcement actions with those of otherpressurized reactor units is contained in Table 1-10.
I E initially attempted to evaluate the regulatory
performance of licensees in two ways. First,
operating plants were evaluated on the basis ofnumbers and types of noncompliance and Licensee
Event Reports for each. Second, IE inspectors
were asked to provide subjective evaluations of thesafety of each operating plant ranging from "acceptable" to "exceptional." This evaluation rated TMI-1
better than 12 of 15 plants in Region 1. 4 However,
because this evaluation was completed in 1978,
TMI-2 was not included.
Unfortunately, efforts to evaluate the performanceof licensees generally have not been put to effective
use by the NRC. The purpose of the appraisal system has been to remove some of the abstract judgment and place the licensee evaluations on a moreconsistent and defendable basis. The licensee appraisal system also has sought to identify thoselicensees who have demonstrated poorer performances so that IE resources can be directed toward upgrading the licensee performance. These
objectives have not been realized, however. IE
resources have continued to be devoted arbitrarily
to some plants more than to others. 5

3. INSPECTION HISTORY AT THREE MILEI SLAND (TMI) SITE
I ntroduction

The IE Region I office has been responsible fori nspecting the TMI site during both the construction
and operation of TMI-1 and TMI-2. The construction
permits for TMI-1 and TMI-2 were issued on May 18,
1968 and November 4, 1969 and the operating
licenses were issued on June 24, 1974 and February 8, 1978, respectively.
The IE office compiled an inspection history of
the TMI site.' This history was limited to the period
from June 1975 to March 1979 for convenience, andwas based on the information readily available in acomputer data system. The information presented
in the IE history includes a tabulation of inspections,but not a detailed evaluation of the inspection reports. For the given period, 136 inspections were
performed for TMI-2. A total of 41 noncomplianceswere found, including 7 deficiencies and 34 infractions. For TMI-1, inspections identified, a total of 95
noncompliances: 42 deficiencies and 53 infractions
were identified.
Noncompliances, deficiencies, and infractions aredefined in the IE Inspection Manual, chapter 0800. 2
A noncompliance is defined as a failure to comply
with regulatory requirement. Items of noncompliance are categorized by IE according to their severity. In decreasing order of severity, noncompliances
i nclude violations, infractions, and deficiencies. A
violation is an item of noncompliance having thesubstantial potential of exceeding a safety limit. An
i nfraction is an item of noncompliance that results ina reduction of preventative capability or causes,
contributes to, or aggravates an incident or occurrence. A deficiency is an item of noncompliance
i n which the threat to the health and safety of the
public is remote and which can be corrected without
undue expenditure of time or resources. The majority of TMI-2 noncompliances were related to administrative procedures and occurred during the

I nspection of TMI-2

The inspection reports for the period August
1977 through February 1979 were also reviewed by
the SIG to identify issues that might be related to
the TMI-2 accident. These reports contain notes on
problems identified by the licensee and by the inspectors, tests observed or reviewed by the inspectors, and general observations by the inspectors
concerning the design and operation of the plant.
Unfortunately, most of the discussions in the inspection reports are quite brief and preclude anevaluation of either the depth of inspector review or

TABLE 1-10. Comparison of enforcement actions
Unit

TMI-1
TMI-2
PWR A
PWR B
PWR C
PWR D

*

6-12/1975
I NF*/DEF*

I nfractons/Deficienc es

2/16
6/10
N/A
N/A
N/A
N/A

1 976
I NF/DEF

1 977
I NF/DEF

1 978
I NF/DEF

20/12
5/1
1 3/1329/10
1 0/101 2/10

22/7
9/3
18/11
21/15
23/17
1 3/11

9/7
1 4/3
1 0/9
6/8
1 8/8
9/9

11 7

the underlying factors contributing to the inspector's
concern. The information contained in these reports
is of such a general, cursory nature that it frequently
is inscrutable. For example, although approximately
one-half of the inspector's time is spent on record
reviews the reports do not reflect the detail of thereview or even delineate the dates on which specific-records are reviewed.
Table I-11 presents a summary of inspection report items illustrative of issues that could relate to
the accident. Two of the three most relevant examples are the inspections performed in early December 1978 which reviewed, to some extent, theprocedure and test results of the emergency
feedwater-system valve lineup verification and operability tests, and the surveillance procedures for the
emergency feedwater-pump functional and valve
operability tests. However, the extent or detail ofthe review is not known, and therefore, we could
not ascertain whether the feedwater block valves
were considered during the inspection.
A third relevant example is the inspector's observation of the generator trip test on January 12,1979.
The final data from the test were not evaluated todetermine whether the pressurizer electromagnetic
relief valve operated properly or if the actuating system conditions meet the acceptance criteria of thetest. Although the relief valve closed, it is notknown whether the test data indicated a potential
operating problem. The inspection reports indicatedthat no discrepancies were found.
I n the final analysis, the degree of relevance of
these inspections to the accident is unknown. For
those inspections where inspectors' concerns werei dentified, it cannot be determined how or to what
extent their concerns were or could have been
resolved, either to prevent the accident or change
its course.
The inspection reports were also reviewed toi dentify the open or unresolved inspection items on
March 29, 1978, which could be relevant to theaccident. These are summarized in Table 1-12. The
open items are certainly important to safety, but
their relevance to the accident has not been determined.
Review of Plant Procedures

The IE inspections generally include a sample review of how procedures are implemented, results ofthese procedures, and administrative controls overthem. IE does not review the procedures, however,for the purpose of approving their adequacy or certifying NRC approval. In fact, Norman Moseley, theformer Director of Region II, told the Commissioners

that "we [IE] always tell the licensee that our review
of procedures is specifically not to approve the procedure, but rather to test for the effectiveness withwhich they review it." Victor Stello, the IE Director,
agreed that approvalof procedures is not given dur8i ng inspections . Because neither NRR nor IE approves licensees' procedures, the NRC does not
approve or review in detail any of the numerous
procedures used to operate the plant during testing
programs or during normal or emergency operations. Nor does the NRC administer managerial
control over processes, such as quality assurance,
emergency plans, containment integrity, and fire
protection.
As a result of inadequate performance by reactor
operations and support staff, IE issued IE Circular
76-07 in December 1976. 9 The circular instructed
licensees to ensure that the plant staff compliedwith safety procedures and that the staff be madeaware of safety-related incidents that have occurredat that facility or at similar facilities. In addition,
licensees were requested to review the administrative controls for plant operating procedures, such as
signoff, tag out procedures, and checklists. No request was made that licensees ensure that theirprocedures were accurate or adequate for their intended purpose.
The drafting, review, and approval of procedures
for TMI-2 were accomplished by Met Ed with assistance of "rental" engineers from B&W and Nuclear
Utility Services, an outside consultant. 10 NRC's roleconsisted of limited auditing of TMI-2 procedures on
a "sampling basis" to ensure that "their technicalcontent was adequate to assure satisfactory performance of intended functions" and that "their format
was in accord with ANSI11N18.7 and the licensee's
administrative contracts."
Development of Operating Procedures for B&W
Plants

The following discussion provides additional information on the methods used to draft, review, andapprove plant procedures. The information is basedon our review of the operation of Davis Besse. On
the basis of the SIG review of precursor events, this
discussion appears to be applicable to all B&W
plants.
Plant procedures are written by the station staff
using the plant's technical specifications and draft
procedures (more recently referred to as Plant
Operating Specifications 12 ), prepared by B&W.
Although procedures of other operating plants havebeen obtained in the past, they have proven to be ofli mited interchangeability because of differences in
11 8

TABLE 1-11. Summary of IE inspection reports
1.

Date

Report Number

Inspector

October 24, 1972

50-320/72-05

April 27, 1973

50-320/73-02

3.

April 16, 1975

50-320/75-03

Folson4.

July 16, 1974

50-320/74-04

FolsonFeb. 18, 1976

50-32/76-01

Narrow

March 18, 1976

50-320/76-03

Fasano/Canter

May 25, 1976

50-320/76-07

CanterJune 28, 1976

50-320/76-08

Narrow

April 12, 1977

50-320/77-10

FasanoMay 18, 1977

50-320/77-15

Narrow

2.

5.

6.

7.

8.

9.

1 0.

FolsonI n a letter to IEHQ (dated October 24, 1972) the Region I Reactor Construction Branch Chief notedthat the licensee was continuing to have problems'implementing a definitive quality assurance program. This problem was also noted in an inspection report dated May 23, 1972 (50-320/72-01).
The inspector noted that the NP-1 Partial data sheets for the 2'/2 inch core spray and the 10 inchpressurizer surge line piping were signed off by a State of Ohio inspector as conforming to the
ANSI B31.7 piping code. The data sheets contained no evidence that they were also in conformance with the Pennsylvania Special Standard WC-1891 as required by the PSAR.

The licensee reported finding a number of defective cast stainless steel socket weld valves, mostof which were check valves (2 inches or smaller). A total of 34 valves, most of which were in the
radwaste system, were rejected. The vendor was Crane Company.
A random selection of drawing on several stick files by the inspector showed that 21 percent of thedrawings had been superseded. A similar situation was reported in August 1972.
The inspector noted that the surge line was installed as shown in FSAR Figure 5.1-5 and B&W
Drawing No. 141562.
The inspector noted that Reg. Guide 1.63 states that a Turbine Trip test from 100 percent power isapplicable to PWRs. The licensee had chosen to perform the trip at 40 percent. The inspector
noted that the NRC had concurred with the licensee's position.
The inspector provided a detailed discussion on remotely operated valves which may become submerged following a postulated LOCA and ECCS actuation. Some deficiencies in valve location
were noted.
The inspector observed that the Isometric Piping Drawing for a section of the Pressurizer Relief
Valve discharge piping had been notated to reflect a recent change in the applicable code classification from N-2 (USAS B31.7 Nuclear Power Piping) to SC (USAS B31.1 Pressure Piping).
The inspector noted that the licensee was conducting a review of Unit 1 problems for applicability
to Unit 2. The inspector had numerous observations concerning the resolution of many of thesei ssues. None of them had specific applicability to this inquiry.
Resolution of Noncompliance 320/74-04: Stress analysis of Main Steam and Pressurizer relief
valve piping. The inspector reviewed Report No. 7.00.006, Rev. 1, "Pressurizer Relief Valve
Discharge Piping Stress Analysis" by Burns & Roe, dated March 21, 1977. No deficiencies werenoted.

119

TABLE I-11. Summary of IE inspection reports-Continued
Date

Report Number

11.

May 23, 1977

12.

June 16, 1977

50-320/77-32

FasanoJune 29, 1977

50-320/77-24

Donaldson

June 29, 1977

50-320/77-24

Donaldson

1 3.

1 4.

1 5.

1 6.

1 7.

1 8.
1 9.

20.

50-320/77-16

Inspector
FasanoResolution of Noncompliance 320/77-09-01 failure to establish document measures and failure tocorrect adverse conditions concerning quality as soon as practicable. The inspector noted that thei ssue had been resolved.
The inspector witnessed the check of the pressurizer code safety relief valve setting. No deficiencies were noted.
Partial Resolution of Unresolved Item 76-18-01: Training program for offsite agencies. The inspector discussed with the licensee the emergency plan training program for various offsite agencies.
The item remained unresolved pending review of the completed program.
The inspector, licensee and representatives of four offsite agencies met to discuss offsite agency
support. The organizations represented were: Dauphin County Office of Civil Defense, Pennsylvania Bureau of Radiological Health, Milton S. Hershey Medical Center, and Londonderry TownshipFire Department.
The inspector verified that the licensee had coordinated pertinent aspects of the Station Emergency Plan development with these agencies and then discussed the anticipated nature and scopeof the support planned.
June 29, 1977

50-32/77-24

Donaldson

August 11, 1977

50-32/77-26-05

Conte

August 11, 1977

50-320/77-26-13

Conte

August 5, 1977

50-320/77-28

Rebelowski

August 4, 1977

50-320/77-28-06

Rebelowski

August 15, 1977

50-320/77-31

Plumlee

The inspector discussed the licensee's planned licensee and offsite agency training program to be
i mplemented under the Station Emergency Plan.
The inspector noted that some procedural errors found by the inspector should have been identified and corrected by the licensee's review and approval program. The inspector also expressed
concern that approved procedures not reviewed during the inspection would exhibit similar probl ems.
The licensee intended to use Preventive Maintenance Check Sheets. The inspector commented
that the check sheets had no provisions requiring an operational test prior to returning the system
to service.
The inspector noted that the licensee had completed the testing of the pressurizer code relief.
The licensee stated that there was a possible design deficiency relating to the design of the reactor coolant pump seals and their cooling water supply. The seals were not designed to accept thetransient associated with station blackout.
The inspector noted that the respiratory protection program was acceptable except that employees
were not specifically evaluated as to their physical and psychological fitness for work requiring theuse of respiratory protection equipment. The licensee acknowledged the deficiency and thei nspector did not classify this as an Unresolved Item.
120

TABLE 1-11. Summary of IE inspection reports-Continued
Date

Report Number

I nspector

21.

Sept. 21, 1977

50-320/77-32

22

Sept. 21, 1977

50-320/77-32

Kellogg

Sept. 29, 1977

50-320/77-34

Kellogg

January 16 1978

50-320/77-42

Kellogg

Feb. 27, 1978

50-320/78-07

Kellogg

Feb. 27, 1978

50320/78-07

Kellogg

Feb. 27, 1978

50-320/78-07

Kellogg

Feb. 27, 1978

50-320/78-07-03

Kellogg

Feb. 27, 1978

50-320/78-07-05

Kellogg

30.

Feb. 27, 1978

50-320/78-08

Bares

31.

March 7, 1978

50-320/78-09

Kellogg

23.

24.

25.

26.

27.

28.
29.

Kellogg

The inspector witnessed the test of the 2B Emergency Feedwater Pump Functional Test. No inadequacies were identified.
The inspector noted that the licensee had experienced problems with the reactor-coolant pumps( RCP); RCP-2A dropped off line after startup, probably due to a phase overload and RCP-2B
developed an oil leak. The inspector reviewed accummulated data for the RCPs. No additional
problems or deficiencies were noted.
During testing of main steam safety relief valves, one valve remained open for an extended period
cf time. The inspector noted that the licensee's action to reseal the valve was timely. The inspector
also noted that 8 of the 12 valves tested failed to meet acceptance criteria. Setpoint adjustments
and retest was planned but there was no follow-up by the inspector.
The inspector reviewed the Generator Trip Test procedure. The procedure controls the response
after a generator loss of load from full power. This information was used to verify adequate NSSS
design and control system performance. No inadequacies were noted.
Resolution of 320/76-00-02 and 320/76-09-01. The inspector reviewed a test demonstrating thatthe response times of the Engineered Safety Systems were within the requirements of the proposed facility Technical Specifications.
Partial Resolution of 320/77-40-02. The volute seals on all four RCPs were replaced and tested.
Testing at normal temperature and pressure remains.
The inspector verified that there are plant procedures providing alternate methods for accomplishi ng an orderly plant shutdown and cooldown in case of loss of normal coolant supply system. No
deficiencies were noted.
The inspector noted that testing associated with the Feedwater Latching System was incomplete.
The licensee noted deficiencies associated with control room status-board position indications forvarious safeguards components.

The inspector reviewed the environmental monitoring program and concluded that the licensee
could implement the required radiological environmental monitoring program for Unit 2.
Resolution of Unresolved Item 320/77-24-01 Adequacy of Station Emergency Plan. The inspector
reviewed the Station Emergency Plan and its implementing procedures to verify that adequate
preparedness would be implemented by the plan and its procedures. The inspector concluded thatt he plan covered all aspects of an emergency.
121

TABLE I-11. Summary of IE inspection reports-Continued
32.

33.

34..

35.

36.

37.

38.

39.

40

41.

Date

March 29, 1978

Report Number
50-320/78-10

Inspector
Markowski

The inspector found some incorrectly stored out-of-calibration torque wrenches. He noted "Thisfinding constitutes one example of an item of non-compliance with the requirements of 10 CFR 50,
Appendix B, Criterion V and the licensee's administrative procedures."
March 30, 1978

50320/78-12

Narrow

April 24, 1978

50320/78-15

Haverkamp

May 31, 1978

50-320/78-17

Haverkamp

August 24, 1978

50-320/78-24

Haverkamp

August 24, 1978

50-320/78-24

Haverkamp

August 24, 1978

50-320/78-24

Haverkamp

Sept. 21, 1978

50320/78-28

Haverkamp

November 8, 1978

50320/78-32

Haverkamp

Nov. 30, 1978

50320/78-33

Haverkamp

This report includes an investigation of an allegation by a welder that he had been required toi nstall an anchor plate in the core flood tank without following proper procedures. The welder
stated that this was a single isolated occurence. The allegation was substantiated.
The inspector reviewed the emergency safeguards actuation that had occurred on March 29, 1978.
After a loss of power to the 2-IV bus, a reactor trip had occurred and the pressurizer electromagnetic relief valve (EMOV) opened The event led to a position indication (energized solenoid) in thecontrol room. A subsequent memorandum was
7 written to CIE headquarters for an assessment of
the fact that the EMOV was not safety-related.
The inspector reviewed Metropolitan Edison Company's letter to NCR:NRR dated May 5, 1978
which included results of B&W's most recent calculation concerning a small break LOCA at TMI.
The inspector discussed the LOCA response actions with selected operators and verified theirunderstanding and knowledge of the procedures. Extensive procedural changes had been made asa result of the B&W analysis.
The main steam line safety relief valves were determined to have excessive blowdown characteristics.
The inspector reviewed LER 78-26/36 dated May 2, 1978. A reactor coolant system wide rangepressure transmitter had failed due to moisture-induced short circuiting in the transmitter terminalbox.
The inspector reviewed LER 78-27/1T dated May 2, 1978 concerning an error in the small break
LOCA safety analysis.
The inspector reviewed Updated LER 78-33/1T dated July 31, 1978 concerning a reactor trip foll owed by RCS depressurization and NaOH injection due to a steam generator safety valve which
had not resealed properly.
Resolution of Noncompliance 320/78-26-01 concerning failure to update emergency procedures
The inspector noted that quarterly surveillance of emergency monitoring kits now includes verification that the information book in each kit includes up-to-date procedures.
The inspector reviewed the report of an emergency safeguard actuation which had occurred on
November 7, 1978, while at 92% power. A heater drain tank low level alarm ultimately resulted inl oss of the 113 feedwater pump. Eventually this led to a reactor trip and a safety injection. During
t he transient the pressurizer level decreased below zero.
1 22

TABLE I-11. Summary of IE inspection reports-Continued

42.

Date

Report Number

Inspector

Dec. 4-8 and 12-14, 1978

50320/78-36

Haverkamp

The inspector reviewed a sampling of test results for procedures Emergency Feed System Valve
Lineup Verification and Operability Test and from the Turbine Driven E.F. Pump Operability Test forthe period July 20-December 2, 1978. The purpose of the review was to verify that operations werei n conformance with Technical Specifications. No discrepancies were found.
43.

44.

Dec. 12-14, 1978

50-320/78-37

Foley/Caphton

The inspector reviewed Unit 2 Surveillance Procedure, "Motor Driven Emergency Feed Pump Functional Test and Valve Operability Test" and verified that all pumps were covered by the procedure.
A sampling of completed test results was reviewed. No unresolved items were identified.
The inspector reviewed the locked valves in the emergency feedwater system to verify they were
l ocked in the required position. No discrepancies were found.
January 9, 1979

50-320/78-36

Haverkamp

January 9, 1979

50-320/78-36

Haverkamp

The inspector expressed concern over the apparent degradation in proper radiation protection
control during the preceding weekend. The inspector noted that the conditions resulted from a
combination of inadequate training and insufficient designation of responsibilities.
45.

The inspector noted several examples of improperly or inadequately completed operating procedures. Most of them were cases of not initialing a step as being completed. However, in one
case the inspector noted that a value lineup had not been fully completed.
46.

January 12, 1979

50-320/78-39

Bettenhausen

The inspector witnessed the generator trip test. The generator trip was followed by a turbine
overspeed trip and a runback in the reactor power to 15%. The inspector noted that the following
test parameters could not be ascertained to meet acceptance criteria on the basis of preliminary
raw data:•

RCS pressure at which the pressurizer spray valve opens or shuts••

Reactor power runback rate•

RCS pressure at which the pressurizer electromagnetic relief valve opens or shuts
Main steam safety valve lift pressure.

No items of noncompliance were noted.

123

TABLE 1-12. Summary of unresolved inspection issues as of March 29, 1978
1.

2.

Date

Feb. 22-24, 1978

Report Number

50-320/78-10

Inspector
Markowski/Beckman

The inspector noted that the licensee had not complied with the requirements of ANSI N45.2.9," Requirements for Collection, Storage and Maintenance of Quality Assurance Records for Nuclear
Power Plants." This issue was outstanding before the operating license was issued on February 8,
1 978. Issue is still unresolved.
Oct. 16-20, 1978

50-320/78-32

Haverkamp

50-320/78-36

Haverkamp

I t was noted in one unresolved item that management had not given final approval to test results
for a number of startup test procedures. The power ascension testing proceeded to the 75% powerl evel but without final approval of the test result at the 15 and 40% power level plateaus. Thei nspector also identified, as an unresolved item pending license review, the need to include admini strative controls for installation of gagging devices on safety or relief valves to be installed during
modifications. Design review of the decay heat and building spray valves has not been completed
by the licensee, and in the event of a major break in the nuclear services river water piping, thesevalves would be subject to simultaneous flooding.
3.

Dec. 4-8 and 12-14, 1978

The inspector noted a number of improperly or inadequately completed operating procedures
which are still open items. Some of the more relevant incomplete procedures were the emergency
feedwater valve lineup, reactor building purge and purification valve lineup, pressurizer operation,
makeup and purification system valve lineup, and safety features actuation systems.
The inspector noted several examples of improper implementation of Technical Specification surveillance procedures. An item of noncompliance was issued concerning containment isolation
valve verification inside containment. The valves are required to be verified as closed during cold
shutdown.
4.

5.

Dec. 12-14, 1978

50-320/78-37

Foley

50320/78-39

Bettenhauser

The inspector found that the licensee's valve testing procedures did not appear to address thetesting requirements for valves with fail-safe actuators. Licensee was to incorporate these valvesi nto the testing procedures. Action has not been completed.
Dec. 28-29, 1978

The inspector was to review final data obtained during a generator trip test from 96% power duringa subsequent inspection. System conditions for pressurizer operations were included in the dataobtained during the test. See inspection summary number 46 in Table 2. Issue is still on thei nspection open list.

procedural philosophy from utility to utility anddifferences in the plant systems. 13
The draft procedures provided by B&W are
prepared by the Customer Services Group withtechnical assistance from other groups. 14 These
guidelines include outlines of specific operating andemergency procedures as well as warranty criteria(e.g., water chemistry on the secondary side mustmeet certain standards). 15 Once these draft procedures are received by the utility, they must be
supplemented with specific plant information. In addition, the utility is free to make any changes it considers appropriate." 6 With the exception of somestartup and test procedures, there is no systematic
review of these actual plant procedures by B&W.

Only when requested by the utility to review a
specific procedure does B&W make any formal ori nformal review of these procedures. 17
We found no indication that plant procedures areformally or informally reviewed within the NRR andthe only review conducted by the NRC is that done
by IE. Principal inspectors and specialists may be
assigned to review plant procedures as part of various inspection modules. For example, during the
preoperational inspections, 60 to 70% of the procedures are reviewed. 18
However, this review
seems to focus primarily on verifying that required
procedures exist and havebeen reviewed by ap19,20
propriate utility personnel.
A small percentageof the procedures (possibly as small as 1%) is re124

viewed by the inspectors for technical content. In
addition, although IE has advocated that the utilities
walk through each procedure, this practice has notbeen adopted by all utilities. The inspector does notalways walk through the procedure to determine
what the operator may see or do. 20 Accordingly,

Sources of such information are rather limited but
i nclude the following:• I nformation from suppliers, such as B&W, Bechtel

and others
Selected Licensing Event Reports received fromgroups such as Edison Electric Institute (utilities
ginspectorhavfud pocerstha
do not receive the bulk of LERs from otherplants)• Bulletins and other publications from the NRC• NRC monthly computer summaries of LERs
(These summaries seldom provide enough information to make a procedural change, which usually requires direct contact with the plant in-

were physically impossible to perform as written. 21
Once the plant becomes operational, the inspectors review approximately a third of the plant
operating and emergency procedures each year.22
During this review, more attention may be given to
their technical content. The procedures are also informally reviewed by the utility engineering group,
which comments on problems they discern.23
As a result of this system, procedures vary considerably in format, content, and quality. Utilities do
not effectively use the "debugged" procedures
developed by other utilities, and numerous changes
frequently are required during the first few years ofoperation. 24
Similarly, operating experience is not effectively
i ncorporated into plant procedures. B&W reviewssite problem reports that document events occurring at specific . plants and can provide guidance tothe utilities through site instructions. 25 However,
the ineffectiveness of this feedback mechanism isdemonstrated by the fact that the Customer Services Group, which is responsible for the preparation of draft procedures, did not review the September 24, 1977, incident at Davis Besse (see Section I.C) to determine if, as a result of that incident,
any changes were required in the draft pro26
cedures.
Moreover, B&W did not receive and thus did notreview the change to the Davis Besse small break
LOCA procedure that discouraged operators fromsecuringhigh pressure injection during a small
26,27
LOCA.
In the meantime, the utility made achange to its small-break LOCA procedure while
B&W was agonizing over the advisability of recommending a similar change (see Kelly/Dunn
Memoranda, Section I.Q. Neither party knew of theother's actions. 28
The principal means by which operating experience is factored into the plant procedures isthrough the efforts of the station staff. One of theaction items that could result from an accident at aplant would be a procedural change, a change
prepared by a member of the station staff and forwarded to the Station Review Board. On the basisof their recommendation, the station superintendent
would make the decision whether to approve thechange. 29 By using essentially the same procedures, information about incidents at other plants
could be evaluated for changes in plant procedures.

• B&W superintendent's group meetings
volved, however.)

Most of this information requires considerable insight and analysis before changes are recognizedand developed, and changes are certainly sporadically applied with varying degrees of success fromplant to plant.
Technical specifications also play an importantrole in the development of plant procedures. The
technical specifications for a plant are issued by the
NRC as an appendix to the operating license. However, these technical specifications are normally
prepared by the vendor and submitted for approvalby the utility as part of its operating license application. Within the B&W organization, the technicalspecifications are prepared by customer services
and licensing groups, with the latter having the lead
responsibility. Although the technical specifications
serve as part of the basis for eventual plant procedures, there does not appear to be any systemati s effort by B&W to ensure that the B&W draft procedures and the proposed technical specifications,also provided by B&W, are consistent. 31 Consistency is left to the utility. 32 B&W normally does noteven see the actual plant procedures, and obviously
cannot review them for consistency with the technical specifications.
Within the utility the technical specifications are
the responsibility of the company's power engineeri ng group. When needed, changes are made as fol23
lows:
1. A facility change request is proposed by thepower engineering group or the station staff
2. A review is made by the station staff and theStation Review Board
3. A review and safety analysis is prepared bypower engineering
4. A review is made by the company Nuclear Review Board
5. A request is sent by power engineering to NRC
for review and approval
125When a change is approved, it is the responsibilityof the station staff, including the Station Review
Board, to ensure that it is accomplished. 29
Findings
1. The inspection reports did not reveal any major
deficiency in the licensee's performance whichclearly contributed to the accident.
2. The inspection reports lack sufficient detail toascertain either the underlying reasons for inspectors' concerns and factors leading to noncompliance.

3. NRC approval is not required for any plant procedures.
4. There is no NRC requirement that the vendor review the utility's operating and emergency procedures to ensure that they are in accordancewith the basic assumptions of the plant design.
5. Operational information is not integrated intoplant procedures.
6. Schedules are not established for the resolutionof important safety problems noted during inspections.

126

REFERENCES AND NOTES"Ad. at 95.

NRC, "History of Inspection at the THREE MILEISLAND SITE," September 1979.
2
NRC, Inspection and Enforcement Manual, 8 Volumes.
3
Miscellaneous Documents (Untitled) from Office ofInspection and Enforcement Files, March 28,1979-May 11,
1979.
4
Letter from W. Paton, NRC, to Atomic Safety andLicensing Board Panel and Atomic Safety and Licensing
Appeal Board Panel, Subject: Board Notification-License
Regulatory Performance Evaluations, dated February
1979.
5
Mosley dep. at 196-197.
6
Grier dep. at 74.
7
Memorandum from D. Stemberg, NRC, to K.V. Seyfrit,"Three Mile Island 2-Pressurizer Relief Valve Control
System," March 31, 1978.
8
NRC Commission Meeting Transcripts (October 23,1979) at 130. Memorandum from D. Sternberg, NRC, toK. V. Seyfrit, "Three Mile Island 2-Pressurizer Relief
Valve Control System," March 31,1978.
9
NRC, IE Circular 76-07, "Inadequate Performance byReactor Operating and Support Staff," December 18,
1976.
10
President's Commission on the Accident at Three
Mile Island, "Report of the Office of Chief Counsel on theRole of the Managing Utility and its Suppliers," at 930,
October 31,1979.
1

Hallman dep. at 39.
Murray dep. at 71.
14
Hallman dep. at 41.
15
Dunn dep. at 67.
16
Faist dep. at 45.
17
Walters dep. at 32.
18
Knop dep. at 61, 63.
19
Kohler dep. at 73.
20
Tambling dep. at 92.
21
Knop dep. at 67.
22
Knop dep. at 59.
23
Miller dep. at 55.
24
Kohler dep. at 75.
25
Walters dep. at 29.
26
Hallman dep. at 50.
27
Dunn dep. at 69; Waiters dep. at
26
Hallman dep. at 52.
29
Murray dep. at 64.
30
1d. at 66.
31
Walters dep. at 32-33.
32
Taylor dep. at 61.
12
13

12 7

31.

C PRECURSOR EVENTS
1. OVERVIEW AND GENERAL DESCRIPTION

curately reflects the ways that these events and issues have been handled.
The more significant precursor matters examined
begin with a 1971 letter to the Atomic Energy Commission from H. Dopchie of Belgium (see Section
I. C.5) which noted a problem with pressurizer level
after a small-break loss-of-coolant accident (LOCA)
from the pressurizer steam space of a Westinghouse pressurized water reactor. In 1974, such an
event occurred at a Westinghouse reactor (NOK-1)
at Beznau, Switzerland (see Section I.C.6).
I n 1975, the Nuclear Regulatory Commission publi shed a report of a detailed 3-year study, variously
known as "WASH-1400," "The Reactor Safety
Study" or "The Rasmussen Report", which attempted to measure the risks in the operation of nuclear
reactors; small-break loss-of-coolant accidents andsmall releases of radioactivity were included (seeSection I.C.7).
I n September of 1977 the Davis Besse nuclear
powerplant of the Toledo Edison Company,
designed by Babcock & Wilcox (B&W), had a transient that was very similar to the TMI-2 accident(see Section I.C.9).
At the same time, at the Tennessee Valley Authority (TVA), Carl Michelson, a nuclear engineer
and a consultant to the NRC's Advisory Committee
on Reactor Safeguards (ACRS), raised to his TVA
superiors some long-considered concerns about thesusceptibility of Babcock & Wilcox designed plants
to very-small-break loss-of-coolant accidents (seeSection I.C.8). TVA submitted the Michelson report

The experience of the nuclear power industry
and the NRC with accidents and episodes presaging
the Three Mile Island (TMI) accident was of particul ar interest to the Special Inquiry Group. Several
such events occurred during the preceding 8 years
i n connection with plants other than the TMI installations. One problem at TMI-2 was also a possible
precursor to the March 28,1979 accident.
The history of the industry was reviewed todetermine (1) if it contained useful foreknowledge ofthe March 28, 1979 problems at TMI, (2) whether
the information was effectively evaluated anddisseminated, and (3) whether that information was
ultimately effectively utilized.
I nitially, the Special Inquiry Group planned to investigate all potential precursor events to determine
their relevance and significance and how they werehandled. However, as work progressed we realizedthat there were a number of additional events andi ssues that although they did not appear to be significant, might have yielded information that would
substantiate the observations we made as a resultof our review of the precursors that we did investigate. These events were not addressed because
the resources required to investigate these peripheral issues were not justified by the expected return. Therefore, the precursors discussed in thisreport are best described as a representative sample of all the precursor events associated with theaccident at TMI-2. We believe that this sample ac129

to Babcock and Wilcox for analysis in April of 1978.
A handwritten copy had been given informally in thefall of 1977 by Michelson to Jesse Ebersole, a close
personal friend and a member of the ACRS. Ebersole, in the process of preparing questions thatwere eventually sent to Portland General ElectricCompany about its Pebble Springs, Oregon, plant,
used Michelson's report as the basis for a question
about operator interpretation of pressurizer level ina B&W plant during a loss-of-coolant accident (seeSection I.C.11).
At Babcock & Wilcox Company Nuclear Power
Generation Division headquarters, a concern arisingout of the incident in September 1977 at the Davis
Besse plant prompted Engineer Joseph J. Kelly (inthe Plan Integration Section) on November 1, 1977,
and Bert M. Dunn, (Chief of the Emergency Core
Cooling Systems Analysis Branch) on February 9,
1978 to urge their management to revise guidance
concerning operator instructions on stopping thehigh pressure injection pumps during accidents (seeSection I.C.10).
At the NRC, perhaps as a outgrowth of the composite impact of the September 1977 Davis Besse
incident, the Michelson report, and Ebersole's Pebble Springs questions, Sanford Israel of the Reactor
Systems Branch of the Office of Nuclear Reactor
Regulation prepared a note signed on January 10,
1978, by his Branch Chief, Thomas M. Novak, concerning pressurizer design in B&W plants. The noteurged that reviewers verify that operators of future
plants be provided adequate information about procedures for terminating high pressure injection flow(see Section I.C.13).
I n March 1978, D. M. Sternberg in Region l, Officeof Inspection and Enforcement (IE), reported to K. V.
Seyfrit in IE Headquarters that TMI-2 had experienced a blowdown (after a reactor trip) on March
29, 1978 because a pressurizer pilot operated relief
valve (PORV) opened after a loss of control power(see Section I.C.15).
An event on March 20, 1978 at the Ranch Seco
nuclear powerplant near Sacramento, California,
i nvolving loss of power to some nonnuclear instrumentation, prompted concerns at B&W about thenecessity for operator education on procedures tofollow when such loss of instrumentation occurs.
B&W wrote to all its site operations managers(except TMI) that "pressurizer level and RCS pressure assure that the Reactor Coolant System
is filled..."' (emphasis added). (See Section I.C.14)

review by the Atomic Safety and Licensing Boardand some of which he personally laid before Commissioners Bradford and Ahearne in March of 1979(see Section I.C.12).
Figure 1-7 is a graphical representation of the significant precursor milestones. Figure 1-8 is a graphical representation of the organizational relationshipof NRC employees who were directly involved withprecursor events or issues.
This chapter reviews these events in detail andgives the Special Inquiry Group's conclusions andrecommendations.
2. CONCLUSIONS AND RECOMMENDATIONS
1. The nuclear industry and the NRC had little or noconcern about what the operators saw during atransient and what they did as a result. Actual
plant operating and emergency procedures were
not reviewed in any systematic fashion by the
NRC or by the vendor. Incidents were assessedalmost entirely from the perspective of the
hardware with little concern about what theoperator saw or did.
I n the design of equipment, much consideration is given to why a piece of equipment will not
perform an anticipated function, (e.g., why a valve
will not open when it should). However, little consideration need be given to why a piece of equipment might perform a function when passivity is
expected. For equipment, this emphasis is proper because a piece of equipment is more likely tofail to perform a required function, than to activate and perform a function for no apparent reason. This logic has been erroneously applied tothe operator. However, people by nature are notpassive. The operators have shown a strong willingness to become actively involved in operating
the plant following an incident. Once the operators decide that they are going to take an activerole in a particular event, they have shown themselves to be very persistent and innovative infinding a way to get a certain function done.
However, defining all of the reasons why anoperator might initiate an action has received
much less attention than it should have received
during the design and licensing of nuclear powerplants. Therefore, with machines, the concern isthat the machines will not perform when theyshould; but with operators, the concern should bethat the operator will perform when they shouldnot.
I n the past, the operators have been essentiall y ignored by the NRC and by the plantdesigners. On the other hand, incidents such as

At NRC's Region III, James C. Creswell, Reactor
I nspector, who was an inspector for Davis Besse,
developed a series of concerns, six of which hesubmitted on January 8, 1979, through channels for130

134

who manufactures them and, therefore, the incident at Davis Besse was applicable, at aminimum, to all pressurized water reactors(PWRs) that have relief valves from the pressurizer.
This hardware orientation can also be seen in
the analysis of specific events. The emphasis of
most of the parties involved in these events has
been on what specific piece of equipment failed
and why it failed. Although this is obviously an
i mportant consideration, an equally importantconsideration which has been almost totally overlooked in the past is the evaluation of the overall
response of the plant, including the operators.
This analysis should include comparison of theactual performance of the plant compared to thepredicted response and an assessment of reasonable "what if" scenarios. To simply say that
we did not have fuel damage so everything musthave gone according to design is not a valid
analysis. If someone with the authority to takecorrective action had assessed the September
24, 1977 incident at Davis Besse and asked," What if the plant had been at a higher power
history?" and/or "What if it had taken the operators longer to identify and isolate the stuck open
PORV?" that person would probably have concluded that an accident very similar to TMI, withsimilar unacceptable consequences, would haveresulted. A few individuals asked these "what if"
questions following the Davis Besse incident;
however, it is obvious that most, if not all, of theparties involved were not sensitive to the significance of these questions and, as a result, essentially ignored the answers.
It must be emphasized that simply improving
the analysis of equipment problems is notenough. The entire industry and the NRC must
broaden their review of operating experience toi nclude an assessment of the overall scenario
and the lessons that can be learned from eachaccident.
3. An NRC mechanism must be set in place to winnow through the mass of material on operational
experience coming in to the NRC in order torecognize events, reports, and responses of significance. It seems clear that this should not be acompartmentalized effort. One unit adequately
staffed as a full-time oversight and "think tank"body is called for. It should not be advisory; itshould have the function of making findings andmandating solutions subject to review by the ultimate governing body of the NRC.
I n order to improve the depth perception ofthis process, it is important that concerned of-the one that occurred at Davis Besse on September 24, 1977 make it quite clear that operators do not consider themselves to be passive
observers during an incident. The operators arean active component. Moreover, they can and do
i ntervene in the automatic features of the plant as
well. Such intervention may be right or very
wrong.
If it is decided that the operators should play
an active role in mitigating and minimizing theconsequences of an accident, then they must be
i ncluded as an integral part of the design andanalysis of the overall system. The operator is
one of the most significant safety-related systems, and he deserves as much attention in thedesign and regulation as other significant safetysystems.
To simply say that the operators should bebetter trained is not enough. The entire accident
analysis of each nuclear power plant must be
redone, including back fitting to operating plants,
because one of the most important safety systems (i.e., the operator) has been almost totallyi gnored. Given the ability and the willingness ofoperators to intervene in the mitigation of an accident sequence, analysis of the response of aplant during an accident is significantly flawed
because it ignores what the operator might do.
If it is decided that the operators should not
actively participate in the mitigation of an accident, then administrative and physical prohibitions must be instituted to prevent all operator
actions during an accident. It is not valid to assume that the operator will be a force for goodwhen his participation is needed, and then pay no
attention to the demonstrated fact that his participation can be a significant force for harm when
it is not desired (i.e., you can't assume that he will
start the pump when he should, unless you also
assume that he will stop the pump when heshould not).
2. The NRC and the nuclear industry must broaden
their analyses of the response of plants during
actual incidents. The past emphasis of such analyses has been on specific hardware problems.
This has been particularly true during the assessment of the generic implications of various incidents. For example, the generic implications of
the September 24, 1977 incident at Davis Besse
were dismissed by many of the parties involved
because the PORV at Davis Besse was designedby one manufacturer while the PORVs at other
B&W plants were designed by a different
manufacturer. This rationalization ignored theobvious fact that PORVs can fail regardless of135fices within the regulatory agency be required tosubmit analyses of events in their area of responsibility. The utilities, the vendors, and architectengineers should be integrated into this analysis
process. To the extent possible, divergent
viewpoints, be it from the IE Regions, from theutilities, from the vendors, or from architectengineers should be encouraged and even provoked. Multidiscipline and multiorganizationalviews should be insisted upon to insure against
the limiting effect of parochialism.
Whether a unit such as we are proposing
should have a permanent staff or a rotating staff,
or a combination is a difficult choice. The experience with a permanent staff suggests that permanence makes for fixed thinking patterns. It
would, accordingly, be advisable to staff anevaluation unit with a limited permanent staff toprovide continuity and a rotation of technicians
assigned to this group for a minimum of 2 and amaximum of 3 years. Assignment should be perceived by management as a recognition of superior performance.
The appropriate spectrum of engineering andscientific disciplines to be represented on thestaff would presumably be what has been foundnecessary to conduct the substantive activities ofthe present NRC with an emphasis on generalists
rather than experts in very narrow engineering
disciplines. To these disciplines it is imperative
to add human engineering specialists to fill the
gap which the Special Inquiry found to be glaring.
The relationship of man to machine, both in thedesign and in the operation of the machine, has
not been addressed at any point in the nuclear
power system in any proportion to the importance of human participation.
By way of comparison and contrast, the Task
Force Recommendations on Operational Data
Analysis and Evaluation for Nuclear Power Plants( SECY-79-371 dated May 13, 1979) proposed,
among other options, a full-time agency group reporting to the Executive Director for Operations.
This has been approved by the Commissioners
as of July 12,1979. This group is, as proposed in
SECY-79-371, an agency-wide office to be
staffed on "a rotational assignment basis" with"an oversight/peer review role." The group willsupervise the operational data analysis review
groups of the several program offices of the NRC.
It is to be the "focal point for interaction with both
the ACRS Subcommittee and any industry
groups dedicated to operational data analysis
and evaluation." Its end function is to develop
recommendations
andprovideguidance.

Although we have not reviewed and do notnecessarily endorse all aspects of this office, wehave observed that one part of the mission of this
newly established Office of Operational Data
Analysis is unlike the office suggested in thisrecommendation. The new Office does not havebinding fact finding and effective directory authority. Such an office, it is submitted, shouldhave the power to mandate solutions. Absent
such power, the new office will likely become
aimless and its analyses will be ignored with impunity. It will be an ivory tower depending entirely on the authority of its opinions in an environment peopled by line specialists who are jealousof their own opinions, skills, and prerogatives.
We recommend that in its area of responsibility
the recommendations of this office shall be followed unless the Commissioners or the directorof the applicable program office direct otherwise.
This directory authority should be added to thecharter of the Office of Operational Data
Analysis.
4. Numerous groups within and among the NRC andthe various industry organizations (e.g., vendors,
utilities, architect-engineers) have been isolated
from each other as a result of physical, geographical, and organizational separation. This
problem has manifested itself in a number ofways, including a lack of acceptance of personal
responsibility to ensure that concerns that areraised are subsequently resolved, and a failure tocommunicate concerns from one part of the organization to other parts of the organization. This
failure to communicate applies equally within thevarious organizations (e.g., within t; i r NRC) andalso between the larger organizations involved(e.g., between NRC and B&W).
For the matters that we reviewed, this problem
was particularly evident in the functioning of IE
headquarters. In almost every case where an attempt was made to pass concerns or informationfrom IE field personnel to other parts of the NRC,or from NRC technical reviewers to IE field personnel; this effort was thwarted, either accidently
or intentionally, by the technical programs personnel in IE headquarters (see Sternberg memo,
Section I.C.15; Ross-Seyfrit note, Section I.C.9;
ACRS briefing on the September 24, 1977 Davis
Besse incident, Section I.C.9).
We found this insulation to be a significant
problem that contributed to the failures observedin every precursor event we investigated. A superficial solution is to recommend massive reorganizations of the various groups involved. However, although reorganization may be a part of136

the solution, it will not alone solve the problem.
We found that simply changing blocks and lines
on an organization chart will not ensure that a
critical piece of information or a critical insight will
get from the person who has it to the person who
can use it. In addition, developing proceduresthat require that everything be documented anddistributed to everyone will not solve the problem
and will only result in the proliferation of an
overwhelming mass of paperwork that will actuall y inhibit the flow of important information. This
problem is compounded by the fact that a pieceof information may not be recognized as important until it is viewed in hindsight, or it may be important only to the recipient not the sender.
We were unable to define specific recommendations to eliminate this problem, although we arecertain that reorganization and emphasis on increased documentation alone will not solve theproblem. We therefore recommend that eachgroup involved develop (with a great deal of assistance from consultants in the area of organizational communications) a program to reduce theinsulation and lack of effective communications
that currently exist. The following measures
which tend to affect the problem are recommended as a minimum:

•
•

•
•

Selection of management dedicated toi nsuring against insulation and isolation andconversely actively devoted to communication and interchange of information.
An incentive program for identification andexchange of safety information, with monetary and honorary awards through salaryi ncreases, cash prizes, promotions, andpublic recognition.
Regular interchange conferences withbroad agendas including industry and NRC
delegates.
I nterorganizational training on communications.

5. Quite apart from the evaluation body at NRC
Headquarters, improvement in the Inspection and
Enforcement activities in the Regions could flowfrom a policy of encouraging inspectors to lookbeyond the inspection module of the moment.
Just as NRR should not use the Standard Review
Plan as a barrier to thought, neither should IE use
i nspection modules. Each inspection should bean occasion to comment on the general state ofaffairs at the particular plant (e.g., cleanliness, theobservable managerial activity, evident personnel
ability, training problems, the overall competencel evel of the utility). At present, Inspectors are

137

under direction to spend 15% of each inspection
on generalized inspection. In practice, this seems
to be accomplished as a timesheet entry without
substance. To fulfill the promise of 15%, or to accomplish the general state-of-affairs observations here proposed, the management of the Regions and Headquarters must provide real impetus and leadership to ensure effective performance by the inspectors, and inspectors in turn
must be trained and encouraged to make thestate-of-affairs analysis.
The resident inspector concept is currently
being implemented at an increasing number ofplants. The obvious benefits are greater familiarity with the plant and its operators. In addition,
unannounced inspections can be increased
without the drawbacks of finding key personnel
missing and activities going on which are inappropriate to module requirements. Whether the
resident inspector becomes too familiar andfraternal with the plant's staff is an issue thatmust be closely monitored and dealt with whenproblems arise. Rotation of the resident inspector, audit of his work by his superiors, and carefulselection of the inspector can guard against
these hazards. In general, however, the resident
i nspector program seems worthwhile.
6. Systematic regional evaluation and analysis of
event and incident reports would be desirable. At
present, for example, in Region III the project inspector assigned to a particular nuclear plant is
expected to review its Licensee Event Reports.
Too often these are so numerous that they preclude his careful attention. To correct this probl em a permanent unit within each Region should
be charged with this review and evaluation task.
It should report to the IE headquarters, to otherconcerned offices at NRC Headquarters and towhatever "think-tank" evaluation unit is set up.
The obvious advantage would be that of being
able to provide Headquarters the view of eventsfrom the vicinage; the nuts and bolts perspective.
7. The Office of Inspection and Enforcement has
displayed a strong tendency to defer to previous
safety analyses that had been performed by
NRR, without making an effort to determine if theanalyses and the underlying assumptions werecorrect. This is a particular problem when prioranalyses are used as an excuse to ignore legitimate concerns, when someone suggests that an
analysis is not complete or correct, or when
operating experience suggests that an analysis is
not complete or correct. An example of this canbe seen in the area of safety-related versus
nonsafety-related systems. IE has a very smallrole, if any, in determining which systems aresafety-related and which systems are not. However, this determination plays a very large role in
the inspection policies and practices used by IE.
These problems are due, to a large extent, tothe physical and organizational separation thatexists between IE and NRR. We recommend that
this separation be reduced by integrating IE andthe Division of Operating Reactors into a single
group.

raised initially by the NRC. Again, very little reflection of this tendency was found, and in fact
several examples were noted where representatives of utilities and vendors had, on their own initiative, raised concerns that they felt wererelevant to the safe operation of the plants (e.g.,
the Kelly-Dunn memoranda, the dual level set
point at Davis Besse, the Michelson report).
3. RELEVANCE OF PRECURSOR EVENTS

8. We found no indication of any specific effort tosuppress the specific information contained in
Creswell's board notification request or to limit its
distribution (see Section LC.12). In fact, NRR significantly expanded the list of licensing boards towhich the material was eventually sent. Although
it appears that most of the steps in this laborious
process are necessary, the time required to cornplete each step should be drastically reduced.
Requirements for the maximum number of worki ng days that a board notification request can beheld at each step in the process (3 working days
would not be unreasonable) should be established and strictly enforced.
9. Simplified event-tree and fault-tree analyses
techniques, similar to those described in theReactor Safety Study (WASH-1400), should be
used to evaluate each nuclear powerplant proposed or currently in operation, to identify and,
where practical, correct weaknesses in design
and in operational procedures.

Two issues can be considered with respect tothe handling of precursor events. First, if lessons
had been learned and applied, how might the actual
accident at TMI been reduced or avoided; andsecond, how does the handling of a precursor rereflea on the overall performance of theutility-vendor-regulator system.
The first issue is itself made up of two questions:. Should additional guidance or information havebeen made available to the operators if a certain
precursor had been handled differently?
, Would the operators at TMI have responded differently during the accident on the basis of that
guidance or information?

The answer to the first question is certainly, yes.
Precursors such as the Kelly-Dunn memoranda or
the Michelson report should have produced guidance that, if it had been used, would have prevented the extensive core damage that occurred at TMI.
Unfortunately the answer to the second question
can never be known for certain. It is impossible todetermine if one additional piece of information integrated with the massive amount of data alreadyavailable to the operators at TMI would have caused
them to diagnose the problem properly and take appropriate actions to prevent the severe consequences that occurred. However, when one looks at
the fact that the massive amount of significant,meaningful information that should have indicated to
the TMI operators that the actions being taken were
i ncorrect, and one realizes that this bulk of information was essentially ignored one must conclude thatany additional guidance produced as a result of anyof the identified precursors might have been equallyignored.
This conclusion does not, however, detract fromthe fact that the second issue, how the precursors
were handled by the licensee-vendor-regulator system, is inherently significant.

10. Event-tree and fault-tree analyses techniquesshould be used by the NRC as one of the major
i nputs to the assignment of priorities and allocation of resources to various reactor safety issues.
11. Perceived higher priority work was frequently cited as a reason for not completing various tasks
or assigning these tasks a sufficiently low prioritythat they were not completed in a timely manner.
The Special Inquiry Group was not able to determine whether this reason was in fact a real justifi cation or whether it was simply a rationalization
by various individuals for not doing tasks thatthey did not desire to do. Better management
control over the priority of assigned work shouldbe implemented. Explicit decisions should bemade about what work will not be done.
12. During the review of the various precursor
events, the Special Inquiry Group looked for andexpected to find a significant amount of antagoni sm between the NRC and the nuclear industry.
However, very little evidence of such antagonism
was found. In addition, a tendency was expectedon the part of the utilities and the vendors to address only those safety issues that had been

4. DEPOSITIONS

For the most part, the testimony given by thewitnesses deposed on precursor matters dealt with138

recollections ranging from 6 months to several
years. These lapses of time have caused some
proportionate loss of remembered detail. Furthermore, the supervening impact of TMI-2 and the multiple investigations that it precipitated, have maderecall a difficult sorting problem. They may, in addition, have imparted to testimony either defensive
bias or even slight distortions. The Special Inquiry
Group kept these witness frailties in mind when thematerial from depositions was evaluated and used.

sidered; and (2) was there a need to find a supplementary signal to close the containment ventilationand pressure equilization ducts.
The AEC responded to Dopchie's letter in a letter
dated September 13,1971.6 In this reply it was concluded that containment pressure and containment
activity signals provided a sufficiently diverse andredundant signal for high pressure injection actuation.
Dopchie responded to this in a letter dated October 14, 1971. He raised the additional issue that
this incident could be different if it were to occur
while the plant was in a hot standby condition, when
the containment might be in a purged condition.
By memo dated November 8, 1971,8 Clifford
Beck, the recipent of the letters from Dopchie, provided information concerning this issue to membersof a Task Force which we believe to be the ECCS
Analysis Task Force within the NRC. In his memo,
Beck concluded that Dopchie had raised a-safetyissue which had not been fully realized by the AEC.
I n addition, he noted that the NRC reply of September 13, 1971 did not satisfactorily resolve thesequestions. However, he did not describe why he felt
the response was deficient. In this memo, Beck
went on to state that Richard DeYoung had
presented the problem to Westinghouse, but that asuitable solution had not yet been developed.
The AEC responded to Dopchie's October 14,
1971 letter in a letter dated September 28, 1972.9 In
this reply, the AEC concluded that based on Westi nghouse analyses of this transient, the core would
not become uncovered and that this issue did notappear to be a significant problem.
This matter was discussed with Westinghouse.
Although some individuals at Westinghouse recall
discussions of Dopchie and his concerns in 1971, a
search of Westinghouse files subsequent to the TMI
accident has produced no documentation of thiscontact. It is not known precisely what aspect ofDopchie's concerns were discussed or what conclusions, if any, were reached. It should be notedthat at about the same time that Dopchie raised hisconcerns, Westinghouse was performing ananalysis of small loss-of-coolant accidents from thesteam space in the pressurizer. This analysis
showed that pressurizer level increased during such
events (as described by Dopchie). However, Westi nghouse did not consider this to be a problem because the operators had over 50 minutes to manually initiate high pressure injection (see Section I.C.6
for additional discussion of this analysis). It is notknown what role Dopchie's concerns played in thei nitiation of this analysis, or how much of thisanalysis, if any, was discussed with the AEC as aresult of Dopchie's concerns.10,11

5. DOPCHIE LETTER-APRIL 27, 1971
As early as April 27, 1971, a concern associatedwith the potential impact of a loss-of-coolant
accident from the steam space in the pressurizer
came to the AEC from overseas. A letter from H.
Dopchie, Directeur of the Association Vincotte (anorganization doing technical evaluation of nuclear
reactor issues under contract with the Belgium
government), asked, "whether the U.S.A.E.C. hasever investigated the consequences of a rupture or
valve opening or failure to close affecting the vapor
space of a Westinghouse pressurizer."2 In thisl etter, Dopchie went on to note that, "the difficulty
occurs because the pressurizer water level would
rise due to boiling in the core hence neither the lowlevel signal nor the associated safety injection signal
would be actuated."3 (Westinghouse plants use asafety injection system which is functionally thesame as the high pressure injection system on B&W
plants.4 For consistency, "high pressure injection
system" will be used to refer to the Westinghousesystem.) On early Westinghouse designs, highpressure injection actuation required both low reacfor coolant system pressure and low pressurizer
l evel. Dopchie did note that high pressure injection
would eventually be initiated by a high containmentpressure signal. However, he concluded that thissignal could be delayed because the release fromthe relief valves would be directed to the quenchtank and not directly to the containment.
Dopchie subsequently sent a letter to the AEC on
June 25, 1971,5 that reflected that he had himself
resolved many of the questions that he raised in his
i nitial letter. For example, he stated that for a small
break (one of less than 2 inches in size) the operator has at least 30 minutes to take action and forl arger leaks (2 to 6 inches) the high containmentpressure signal should actuate high pressure injection. However, in this discussion he did notdescribe what would cause the operator to take action. In his letter he did note two remaining probl ems: (1) must a leak larger than 6 inches be con139

Specific Conclusions

1. As early as 1971, a concern had been raised
about the response of pressurizer level during asmall loss-of-coolant accident from the top of thepressurizer. Although this concern was raised in
the context of a Westinghouse design and in relation to the potential for misleading the automatic
i nitiation signal for high pressure injection on thatdesign, it is conceivable that additional analysesof this issue might have provided some insighti nto the fact that operators might also misinterpret pressurizer level during such an event.
2. There is no indication that any consideration wasgiven to the operator interpretation of pressurizer
levels during this type of transient and lessons
were not learned as a result of the concerns
raised by Dopchie.
6. BEZNAU INCIDENT-AUGUST 20, 1974

On August 20, 1974, an incident occurred at the
NOK-1 nuclear powerplant in Beznau, Switzerlandthat bears some similarity to the accident that subsequently occurred at Three Mile Island. (This incident has come to be known as the Beznau incident. The reactor, although located in Beznau,
Switzerland, is named "NOK-1." There is no"Beznau Reactor.") The NOK-1 plant was designed
by Westinghouse. The design is similar to nuclear
powerplants that were built by Westinghouse in the
United States.
The particular incident in question began with thereactor operating at 100% power. A trip of one of
the two turbine generators occurred. As a result,
the reactor coolant system temperature and pressure increased rapidly and both PORVs opened.
One PORV failed to close and a subsequent
depressurization of the reactor coolant system occurred. The reactor tripped on low pressure as aresult of this depressurization. As pressure continued to decrease, steam formed in the reactor
coolant system hot leg and pressurizer level began
to rise. It eventually increased past the 100% point
and remained offscale for 3 to 5 minutes. The
operators were able to identify that the PORV wasopen in approximately 2 to 3 minutes and shut thei solation valve (there is no indication of what caused
the operators to realize in such a short period ofti me that the PORV was open). After the PORV wasshut, the pressurizer level fell rapidly as the steam
bubbles in the reactor coolant system collapsed.
Finally, approximately 12 minutes into the incident,
the pressurizer level reached the 5% point and highpressure injection was initiated.
140

In this particular design, a coincident initiation
was required for high pressure injection actuation.
This initiation required both a low reactor coolant
system pressure and a low pressurizer level.
Therefore, because the pressurizer level went offscale high due to void formation in the reactor
coolant system, the pressurizer level did not decrease initially and did not cause high pressure inj ection to begin until 12 minutes into the incident.
The incident was analyzed by a team from
Westinghouse's Brussels, Belgium office and a report prepared. This report was distributed to various individuals in the Westinghouse domestic reacfor offices in Pittsburgh, Pa. The analysis indicatedthat all existing
protection systems had performed
12
properly.
This conclusion was based in part on an analysis
of a small LOCA from the steam space in the pressurizer which had been performed in 1971. This
analysis showed that during such an event, pressurizer level would rise and prevent automatic initiationof high pressure injection. 13 The analysis also
showed that the operators had approximately 50
minutes to manually initiate high pressure injection
before core damage would begin. 14 Westinghouseconcluded that this amount of time (20 minutes isnormally considered an adequate period for an
operator to take required manual actions) and thei ndication available to the operator (Westinghouseplants have, among other indications, direct indication of the PORV position) were sufficient to provide
adequate protection. 15 This conclusion was substantiated by the fact that the operators at Beznau
i solated the PORV in 2 to 3 minutes.
It should be noted that prior to the TMI accident,
Westinghouse guidance to utilities concerning small
LOCA procedures did not provide specific warnings
that pressurizer level might increase during such an
event. The Westinghouse operator training program
included a stuck-open PORV and the operator was
i nstructed how to recognize this event. However,the Westinghouse simulator did not indicate a risingpressurizer level, but only indicated a more slowly
decreasing level. 16
The results of the 1971 anaylsis had been documented to the AEC in the Safety Analysis Report( Amendment 1 dated 17October 1972) for the
RESAR-3 standard plant.
Although this report did
not specifically state that the pressurizer level would
i ncrease during such an event, it did state that for
breaks in the 2- to 6-inch range, high pressure injection might not result. The report also noted thata delay of high pressure injection of more than 50
minutes would not result in core uncovering.

Beginning with RESAR-3, the standard Westinghouse design was changed to require only low
pressure to initiate high pressure injection. Thischange was primarily the result of operating experience which indicated that spurious actuation of highpressure injection would not be a problem if thecoincident pressure and level requirement was eliminated. Westinghouse considered changing older
designs, but decided that because of the time andi ndication available to the operator, backfitting of
this change was not required. 18

After the accident at TMI, Westinghouse provided
guidance to plants that still have the coincident low
pressurizer/low pressurizer level high pressure
injection. This guidance pointed out that during
small LOCAs from the pressurizer, there may be a
problem with pressurizer level hanging up. By letter
dated April 10, 1979, 20 Westinghouse informed the
NRC that they had advised utilities that the problem
could exist and they were recommending that theoperators be specifically instructed to monitor pressure and manually initiate high pressure injection if
pressure dropped below the actuation point.

The original report of the Beznau incident was
not submitted to the AEC at the time that it was
prepared because the plant had responded as expected. The NRC eventually became aware of thei ncident at Beznau during discussions with Westinghouse employees following the TMI accident. The
NRC subsequently obtained from the Swiss government the Westinghouse report and another report
prepared by the Swiss. Paradoxically, however, because of the current regulatory requirements withrespect to proprietary information, the Swissgovernment was able to designate this information
as proprietary which would have prevented thedissemination of the details of this event to the publi c. In fact, it was initially intended that the only
reference that would be made in any public NRC
documents with respect to the Beznau incident, wasa statement that had been approved by the Swissgovernment. This statement said, "We are aware of
one incident at a foreign reactor designed by Westi nghouse which occurred a number of years ago inwhich a PORV was challenged during a turbine triptransient and failed to reclose when pressure decreased. The failure to close was detected in a few
minutes by the operators who immediately isolated
the valve by closing the blocked valve in series with
the PORV. This action terminated the incident. The
failure to reclose was due to the rupture of the casti ron frame between the valve operator and the valve
body which was caused by a water slug hitting thevalve. The source of the water slug was the loop
seal located between the pressurizer and the relief
valve. Investigation of this event identified the causeof the valve failure to be design error which, weunderstand, has been subsequently remedied." 19
There is no indication in this statement that pressurizer level failed to decrease and that high pressure
injection was inhibited as a result of the response of
the plant. It was only after the inappropriateness of
the withholding of this information from the public,
was raised by a number of individuals, including
members of this Special Inquiry, that the proprietary
restrictions were removed.

Specific Conclusions
1. An incident occurred at the NOK-1 nuclear planti n 1974 that demonstrated the phenomenon of increasing pressurizer level during a small loss-ofcoolant accident from the steam space in thepressurizer. This phenomenon was subsequently observed at the Davis Besse plant in September 1977, and during the TMI accident. In thespecific case of the Beznau incident, the highpressurizer level caused the high pressure injection to fail to initiate. At Davis Besse and TMI,
the high pressure injection system initiated but
was subsequently stopped because the operators erroneously interpreted the high pressurizer
l evel.
2. The relevant phenomenon (i.e., increasing pressurizer level during a small LOCA from the pressurizer steam space) had been previously identified by Westinghouse. Therefore, the plant
responded as expected. The implications of thisphenomenon but not the phenomenon itself, hadbeen reported to the AEC prior to the Beznau incident. It is not known how clearly the AEC
recognized this phenomenon as a result of thismatter. However, it does appear that the AEC
was never explicitly informed that for older Westi nghouse designs (i.e., prior to RESAR-3) operafor action was required during a small LOCA fromthe steam space in the pressurizer. As a result, it
was not possible for the AEC to incorporate thelessons that might have been learned from thisincident into the licensing of Westinghouse plants
or PWRs in general.
3. Because of the restrictive nature of the current
regulations with respect to proprietary information received from foreign governments, it is very
possible that the information contained in the
Beznau report would not have become part ofthe public record even in light of the TMI accident. However, it must be recognized that141

there is a trade-off between restrictive
proprietary information provisions that allow aforeign government to provide information thatwill subsequently not become part of the publicrecord; and the fact that if foreign governments
can no longer provide this information with confidence that it will not become public, they will refuse to provide the information in the future.

7. REACTOR SAFETY STUDY (WASH-1400)OCTOBER 1975

I n 1975 the NRC published the results of an
extensive three year study which attempted toquantify the risks associated with operation of a
nuclear reactor. The report was formally titled, "The21
It has also come to be
Reactor Safety Study."
known as "WASH-1400" or "the Rasmussen
Report."
WASH-1400 is a precursor to the accident at TMI
for a number of reasons.
First, WASH-1400 identified the category ofsmall-break LOCAs as one of the most significant
contributors
to the risk from nuclear reactor opera22,23
tion.
Of particular concern was the smallest
class of reactor coolant system breaks ( 1/2 i nch to 2
i nches effective diameter) which included a breakequivalent to the stuck open PORV at TMI (approximately 1 inch effective diameter). This dominance ofvery small LOCAs over larger LOCAs was foundeven in the most serious (with respect to radioactivi ty releases from the containment) categories ofaccidents identified in WASH-1400. For example,
the probability of the most serious category of accident assessed in WASH-1400 being initiated by avery small LOCA is 50 times greater than the probability that it would be initiated by a large LOCA. 24
This dominance was due primarily to the fact that
small pipes are considerably more common thanl arge pipes, and large pipes are installed using
25
stricter codes and requirements.
Despite this emphasis in WASH-1400 on the significance of small LOCAs, the NRC continued toplace a great deal of emphasis in the licensing process and in research allocations, on large LOCAs. 26
Had the emphasis been shifted to these very small
LOCAs, it is possible that a better understanding of
the subsequent events at Davis Besse (September
24,1977) and at TMI might have been developed.
Second, WASH-1400 emphasized that small
releases of radioactivity resulting from various plant
accidents are much more likely than large catastrophic failures releasing large quantities of radioactivity. For example, the least severe category of accident consequences (category 9), which includes
the level of releases that occurred at TMI, 27 was

142

found to be over 400 times more likely than the28
most severe category (e.g., category 1).
As a result of this conclusion, the NRC shouldhave recognized that these less severe accidents
deserved a significant emphasis in the regulatory
process because the probabilities indicated that an
event of this type would occur in the coming years.
As has been shown by the accident at TMI, increased emphasis should have been placed on emergency planning and dissemination of information
during such high probability but low consequence
events. This is particularly true when one recognizes that although the radioactivity released during
these events did not produce a significant physicalhealth effect, the psychological stress caused bythese events may well have been significant.
Third, the event-tree and fault-tree analysis techniques used in WASH-1400 were shown to be an
excellent technique for analyzing the relative significance of various safety issues. These techniques
were sufficiently well developed to be used as a
guide for selecting the issues that were most
relevant to safety and deserving of a high priority.
I n addition, these techniques could identify
weaknesses in the existing design and operatingprocedures that require improvement. In fact, during
the WASH-1400 analysis, a significant weakness inthe design of one of the two plants used as thebasis for the analysis was identified and subse29
quently corrected.
This weakness had not been
identified by the conventional design and licensing
process.
Although the NRC staff and the nuclear industry
have used the event-tree and fault-tree analysis
described in WASH-1400 to a limited extent, thisquantitative technique has not been used extensivel y to assess specific plant designs or the relative
priorities of reactor safety issues. Instead, the staff
has relied on more qualitative decision criteria suchas engineering judgment and deterministic decision
making. It can be argued that it is impractical to use
the techniques described in WASH-1400 because of
the ti me and expense required.
However,
Rasmussen has testified that one can learn about
90% of the information acquired during the Reactor
Safety Study for a tiny fraction of the total effort expended by Rasmussen's group. He pointed out thatmuch of the effort expended during the study wasused to see if an exhaustive study would provide
different answers than a cursory, simpler study.
The conclusion was that one can learn a great deal
from rather simple and much less exhaustive analyses. 30
Fourth, many of the parts of the actual event that
occurred at TMI were described in the various
scenarios that were analyzed in WASH-1400. The

expertise to develop credible subjective probabilities. Even when only bounds for certain parameters could be obtained, the method was still
useful if results were properly stated. The report
noted that although the NRC had moved somewhat in the direction of using the methodologies
described in WASH-1400, a faster pace wasrecommended.
. WASH-1400 was inscrutable and it was very difficult to follow the detailed thread of any calculations through the report. In particular, the Executive Summary was a poor description of the contents of the report, should not have been portrayed as such, and had lent itself to misuse in
the discussion of reactor risks.

TMI accident began as a transient event. During thei nitial stages of the accident, the scenario closely
followed a loss of main feedwater and subsequentl oss of auxiliary feedwater scenario described in
WASH-1400. The WASH-1400 scenario included arecognition of the possibility that a PORV could
open and fail to close, a malfunction which occurredat TMI. In the same vein, one of the transients considered as a separate initiating event was an accidental opening of the pressurizer safety or relief
valve. The open PORV is, moreover, the same sizeas the very small LOCAs assessed in WASH-1400.
WASH-1400 did not, however, consider the possibility of the operators stopping or reducing high pressure injection flow, which was the most significant
contributor to the severity of the consequences of
the accident at TMI. 31
I n response to the comments made on WASH1400 by a number of sources, and particularly
Congressman Udall, Chairman of the House Committee on Interior and Insular Affairs, the NRC established the Risk Assessment Review Group in July
1977. The purposes of this one year review of
WASH-1400 were to:reviewed
the results
The Commissioners
described in the Lewis Report and on January 18,
1979 issued an "NRC Statement on Risk Assessment and the Reactor Safety Study Report(WASH-1400) in Light of the Risk Assessment Review Group Report." 34
The Commission noted that although the Review
Group praised the study's general methodology andrecognized its contribution to assessing the risks ofnuclear power, the Review Group was critical of the
Executive Summary, the procedure followed in producing the final report and the calculations in the
body of the report. The statement was essentiallynegative in tone thus creating a misleading pictureof the Lewis Report's findings and recommendations
on WASH-1400 and its Executive Summary.
Although the Lewis Report found the study's absolute numerical assessment of risk and the Executive
Summary to be deficient, it unequivocally endorsed
WASH-1400 techniques as an aid in technical decisionmaking:• Clarify

the achievements and limitations of
WASH-1400.
• Assess the peer comments thereon, andresponses to those comments.
• Study the present state of such risk assessment
methodology.
• Recommend to the Commission how (and whether) such methodology can 32
be used in the regulatory and licensing process.

The results of this assessment were published in
September 1978 as a report titled, "Risk Assessment Review Group Report. (NUREG/CR-0400)." 33
This report has come to be known as "the Lewis
Report."Among the several conclusions reached by the
Lewis Report were the following:

Fault-tree/event-tree analyses should be among
the principal means used to deal with generic safety issues, to formulate new regulatory requirements, to assess and revalidate existing regulatory
requirements, and to evaluate new designs.

The negative tone of the Commission's statement
and its confusion about what the Lewis Report criticized and what it endorsed is puzzling. This collegial action resulted in perceived policy direction andhad a negative impact on the quality of the licensing
and regulatory system.

• WASH-1400 was a conscienious effort to apply

the methods of fault-tree/event-tree analysis toan extremely complex system.
• WASH-1400 contained a number of sources ofconservatism and nonconservatism in the probabili ty calculations which were difficult to balance.
The report concluded, however, that although the
Review Group was unable to determine whether
the overall probability of a core melt was too highor too low, they were certain that the error bands
were understated.
• The methodology used in WASH-1400 was
sound and should be developed and used more
widely under circumstances where an adequate
data base exists coupled with sufficient technical

Specific Conclusions

14 3

1. WASH-1400 is a precursor of the TMI accident to
the extent that it highlights the dominance of verysmall LOCAs over large LOCAs. However, the
NRC staff has continued to place disproportionate emphasis on the less significant
large LOCAs in the licensing process and• Transition from natural circulation to pool-boilingresearch allocation. It is not possible to determine what effect, if any, an increased emphasis
on very small LOCAs, which include the stuck
open PORV that occurred at TMI, might have hadon the accident at TMI.
2. Fault-tree and event-tree analysis techniques
described in WASH-1400 are an effective methodology for identifying weaknesses in particular
designs and for assigning priorities andresources to various reactor safety issues. The
NRC staff did not attempt to use these techniques to the extent warranted.
3. The actual analyses conducted during the Reacfor Safety Study were not particularly relevant to
the human error aspects of the TMI accident that
directly contributed to the severe consequences.
4. The NRC seemed unable to digest WASH-1400
and put its methodology to work. NRC's
response was to commission one study after
another.

may be a problem because of the time delay incurred while waiting for the water level in the Ubend region of each hot-leg pipe and in the steam
generator tubes to drain to the secondary side
water level.
• I solation of breaks would remove the break as asource of decay heat removal without assurance
that some other effective means of decay heatremoval could be reestablished.
• During refill accumulation of noncondensible
gases could prevent reestablishment of natural
circulation.

The report noted that, if repressurization occurs,
relief through the pressurizer safety valves would
constitute a path for decay heat removal. However,these valves are not qualified for two-phase flow,
and during this scenario the operator would be
unaware of what is happening to the reactor vessellevel. The report also noted that pressurizer level inthe indicating range is not necessarily an indicationthat adequate core coverage is being achieved.
Adding to these concerns was an uncertainty associated with unknown vessel level and the adequacy of emergency operating instructions and operator training for this event.
The very small break postulated for this report
was assumed to be located at the top of the coldeg plegpipe. However, the break location was notthought to be a major influence.
The report also raised the possibility that thepressurizer surge line loop seal had the potential for
inhibiting steam entry into the pressurizes.
The handwritten draft contained a brief reference
to operator interpretation of pressurizes level:"Note, the presence of a pressurizes level is not anindication that adequate core coverage is being
achieved."
The discussion of pressurizes leveland operator actions based on pressurizes level was
greatly expanded in a subsequent draft.
Michelson gave a copy of the draft report toJesse Ebersole to enable Ebersole to get more information about small breaks by asking some questions during the ACRS review of the Pebble Springs
application. Michelson had been a close personal
friend of Ebersole for many years and had worked
for him in various capacities over approximately 20
years while Ebersole was employed by NA. (Ebersole retired from NA and joined the ACRS in 1976.)
Ebersole had encouraged Michelson to become aconsultant to the ACRS in areas of nuclear systems
analysis and nuclear plant security.
Ebersole used the Michelson report in two ways.
First, it was the basis for some questions raised by
the ACRS and eventually asked of Portland General

8. MICHELSON REPORT-SEPTEMBER 1977
I n September 1977, Carl Michelson, an employeeof the Tennessee Valley Authority (TVA) and a consultant to the NRC Advisory Committee on Reactor
described (ACRS), prepared a report in which hedescribed some issues concerning the response of
B&W 205-fuel-assembly pressurized water reactors
during very small-break loss-of-coolant accidents.
Michelson wrote the report as the culmination oflengthy consideration of such very small breaks, including considerable discussion with Jesse Ebersole, a member of the ACRS. Michelson had become concerned that the information available fromthe nuclear steam supply system vendors was notadequate, and that the models used to predict the
behavior of small breaks were not valid predictorsof the response of very small breaks. This report," Decay Heat Removal Problems Associated with
Recovery from a Very Small Break LOCH for B&W
35
is dated September 1,
205-Fuel-Assembly PWR,"
1977. This report was handwritten.
The very-small-break LOCH described in this report (i.e., break size less than 0.05 square feet) was
defined as one in which the steam generator must
remove a significant portion of the decay heat, orelse reactor coolant system repressurization occurs. The report raised numerous issues and conterns, including:• Depressurization rates are slow and might lead toi nadequate makeup rates from the high pressure
i njection pumps.

144

Electric Company (the applicant) as part of the review of the Pebble Springs application (see Section
I. C.11). Second, Ebersole informally passed the report on to Sanford Israel, a first-line supervisor in
the NRC Office of Nuclear Reactor Regulation, withwhom he had formally and informally discussed
small-break LOCAs for many years. Ebersole gave
Israel the report in the context that, although he(Ebersole) believed that the report described a
problem, Israel could pursue the matter at his own
volition.ss It should be noted that Michelson did notformally submit the report to the ACRS, and Ebersole did not formally submit it to the NRC. Michelson has testified that he did not submit the reportformally because, although he felt strongly enoughabout it to make sure that other people were awareof his concerns, he did not feel so strongly as to beli eve the matter had to be forced. 39 Ebersole testified that he could have formally submitted the reportto the NRC for review, but he did not do so because
he did not know if the issues raised constituted a
critical safety issue.40
Upon receiving the report, Israel reviewed it briefl y, but did not read it in its entirety. He reviewed thereport to determine if it contained any new information and concluded that it did not. Shortly after receiving the report, Israel was aware that B&W had
made a presentation dealing with small-break LOCAs in response to the question asked by the
ACRS as part of the review of the Pebble Springs
application. Because he did not receive any more
feedback from the ACRS he assumed that they
were satisfied by the Pebble Springs response andhe did not think about the issue any further. 41
I srael has testified that he did not focus on thespecific concern raised in the report associated with
operator interpretation of pressurizer level. However, Israel believes that the Michelson report may
have played a role in his eventual preparation of amemo concerning the question of the loop seal
design of the surge line in B&W reactors (see Section I.C.13). Furthermore, Israel continued the distributton of the report by giving a copy to Gerald
Mazetis, another first line supervisor in the NRC Office of Nuclear Reactor Regulation, and Mazetis
briefly reviewed it. Mazetis, too, did not see anything in the report that caused him to take action.42
However, it appears that neither Israel nor Mazetis
ever reviewed the paper in detail,and their involve43,44
ment with it ended at this point.
Michelson testified that he never received a response from the
NRC concerning his report, but was not concerned
because45 he was assured that the NRC had his material.
I n January 1978, Michelson completed a revised
typewritten draft of his report 4g which included

more analytical calculations and expanded severalof the discussions. Michelson provided a copy ofthis draft report to Ebersole, but apparently thetypewritten draft was not given to anyone at the
NRC. The introduction to the expanded version
stated:This report gives an account of some initial considerations of a class of very small-break LOCAs(probably less than or equal to 0.05 ft 2 ) for a B&W
205-fuel-assembly PWR which may have an associated decay heat removal problem. 47

This introductory summary also stated:

Also of concern is the possibility of break isolation
by operator action resulting in repressurization andslug or two-phase flow through a pressurizer safetyvalve. These uncertainties may reflect on the adequacy of proposed emergency operating procedures and operator training for a very small
break LOCA. 48

Of particular interest to this Special Inquiry is
Section 4.6 of the revised report which discussed
the subject of pressurizer level indication. This discussion had not been included in the earlier
handwritten draft. This new section stated:

If the break is at the top of the pressurizer steam
space, a rapid pressurizer refill can occur. During
the transition to pool-boiling and while in poolboiling, the level should stabilize even though thecore may be uncovered. Therefore, pressurizer
level is not considered a reliable guide as to corecooling conditions. No other primary side level indication is provided.49

This section also stated:

A similar problem with pressurizer level indication isfound in Section 4.5 relative to HPI pump trip. A fullpressurizer may convince the operator to trip the
HPI pump and watch for a subsequent loss of level.
Although this response appears desirable, a fullpressurizer may not always be a good indication ofhigh water level in the reactor coolant system. For
i nstance, the steam bubble which is trapped in thepressurizer may be vented by actuation of thepressurizer vent valve due to high pressure
developed in the reactor vessel top plenum or by
operator action. The vent valve will subsequently
close, but the pressurizer may be filled solid with asubcooled liquid. The loop seal configuration of thepressurizer surge line allows the pressurizer toremain filled as the reactor coolant system waterlevel drops until system pressure is below saturation pressure of the pressurizer liquid inventory.
This may take a long time, if system pressure is set
by a requirement to remove some of the decay
heat to the steam generator at 1270 psia. Thus, afull pressurizer is not considered a reliable indication for prescribing certain operator actions such as
HPI pump trip. 50

Michelson considered whether the report should
be provided to the NRC under the provisions of 10
145

house LOCA analysis work. Your more detailedtransient calculations based on realistic system andcore thermal-hydraulic models would be an appropriate verification that no serious problems exist. 54

C.F.R. Part 21. However, he concluded that hecould not clearly identify this item as reportable because it was sufficiently tentative to permit sending
it to B&W for comment before formally submitting itto the NRC. 51 Michelson forwarded his report to
B&W for review, by letter from D. R. Patterson of
TVA to James McFarland of B&W dated April 27,
1978. 52 This letter stated that increased ACRS interest in, and questions concerning, very smallbreak LOCA's had prompted NA to take a closer
look at this problem.
Michelson testified that he made reference to the
ACRS concerns (which were actually a result of his
report, not a cause of it), and to the possibility ofadditional questions during the review of NA's Bellefonte application to encourage timely consideration by B&W. He has testified that he expected areply in no less than 3 to 4 months. -r3 The NA letter
related further that the enclosed report was a preliminary draft study that reflected NA's initialthoughts and concerns and requested that B&W review this work and give its views. NA requested
that, after B&W had reviewed this study, a conference call be arranged to discuss the matter with
B&W and TVA, and a meeting be scheduled to examine the entire issue of very small breaks.
The letter did not indicate that a written response
was desired or required. The central concern addressed in the cover letter involved the fact that a
number of possible situations existed that might impede decay heat removal. For example:

The Michelson report was initially received byRobert Lightle, Associate Project Manager at B&W,
who immediately forwarded it to Bert Dunn, UnitManager, and Robert Jones, Senior Engineer, in the
ECCS Analysis Group.
To place the report in perspective, Lightle testified that B&W had received approximately 10000
l etters from NA since B&W began work on the Bell efonte project in 1970. Approximately 6000 lettersoriginated in the engineering group in Knoxville, of
which Michelson is a member. The remainder camefrom the materials engineering group in Knoxvilleand the contract group in Chattanooga. About
7000 to 8000 letters raised a question or concernthat NA wanted B&W to address. Of these, approximately 2000 were associated with plant safe55
The Michelson report was one of those 2000
ty .
l etters.

Lightle also testified that B&W's scheduling ofwork requested by a customer was based on theneed for the results to meet a specific licensing or
construction milestone, insistence by the customerthat a specific task be completed, or both. The
response to the Michelson report was not perceived
as directly affecting any milestones, although it
might have indirectly affected the Safety Analysis
Report scheduled for completion in early 1979.
Lightle did not feel that NA pushed for completion
Although Michelson recalls reof this review.
questing several times of his supervisorsthat B&W
57
be contacted concerning a response,
recalls only a single call concerning the report prior to58
November 1978.
Jones recalls receiving the report in May 1978.
His recollection is that he scanned it and considered
it to be too detailed to review immediately becauseof higher priority work. Although the very small
breaks described in the report had not been specifically analyzed, he believed that they had been reviewed from the standpoint of being bounded by the
analysis of larger small breaks. Jones also felt that,while the report described some validsa
concerns, it
did not raise any new or unique issues.
On the basis of Jones' initial appraisal that there
was not anything particularly alarming, he and Dunn
decided that the review of the report could wait andcould be completed on a more leisurely schedule.
The high priority work that Jones had been working
on when the Michelson report was received wascompleted in August or September of 1978. Work

• A steam bubble could form at the top of the hot
leg which would interrupt natural circulation.

• Transition from natural circulation to pool-boiling

could be a problem because of the time delay
while waiting for the steam generator tubes todrain down (it is noted that this could result insystem repressurization).
• Refill of the system might not restore natural circulation if sufficient noncondensible gases arepresent.
Other concerns noted in the cover letter were:• The operator might isolate the leak and remove it
as a source of decay heat removal.
• The code safety valves on the pressurizer are
not qualified for the passage of two-phase fluid.
• Pressurizes level is not a correct indicator of water level over the reactor core.
The TVA cover letter closed with the following
statement:

We assume that the situations and concerns whichhave been identified above and in the attacheddraft study have been considered in your own in146

on the Michelson report was, nonetheless, still del ayed because of higher priority work that had been
put off during the earlier efforts. In September,
Jones did reread the report, but found it difficult todetermine how to respond.
Elsewhere in the B&W organization, James Taylor of B&W's Licensing Branch also received a copyof the report. He referred it to Henry Bailey of his
staff. Bailey reviewed the report and prepared amemo on May 25, 1978 which concluded that thephenomena described would all occur while thecore remained covered. However, he also noted
that, "A more valid concern may be the subject ofoperator action and the potential for erroneouspressurizer level." 61 He concluded that, "Bert Dunnplans to start looking at the report next week to see
what's there and to consider what62action or investigation should be pursued (if any)."
In the fall of 1978, Michelson became increasingly
concerned because he had not received a response
from B&W. He placed increasing pressure on the
personnel at NA who were in contact with B&W toattempt to get the review completed. Finally, in December 1978, a conference call was arranged andi ncluded a number of people from both B&W and
NA. The bulk of the conversation (which lasted
approximately 1 1/2 hours) involved Michelson andJones discussing their positions on the analysis ofsmall breaks.
Michelson's concern centered on whether or not
B&W had performed calculations to determine if thecore stayed covered for breaks under 0.05 squarefeet. Jones countered that, although specific calcul ations had not been performed, extrapolation ofdata from larger small breaks indicated that keeping
the core covered was not a problem. He also pointed out that the NRC had verbally accepted this conclusion that smaller breaks were not a problem.
Michelson then asked that B&W identify areas
where their results differed from his results, andsince B&W's calculations were more sophisticatedthan TVA's, to inform NA of their errors. Lightle
pointed out that to give such an answer would require a detailed calculation on the part of B&W, andJones added that he did not feel that such an effort
was warranted.
Michelson then asked that B&W reply to his earlier letter, describing how they had replied to the
NRC with respect to the very small breaks (lessthan 0.05 square feet) but not by doing any actual
additional analysis. B&W asked that NA provide awritten description of their remaining concerns tofocus the issues. This one-page summary 63 of thei ssues was prepared by Michelson, and forwarded
to B&W by telecopy. This document states, in part," When replying to our letter, please specifically ad64
dress the following statement of the problem."This summary statement then listed a number ofmatters not relevant to this Special Inquiry. It should
be noted that the list did not include the issue ofpressurizer level indication and possible operator
action as a result of high pressurizer level indication.
The summary concludes, "Please indicate which
portions of your reply are based on analysis 65
and indicate their availability to NA and the NRC."
Jones prepared a response to Michelson's reportand forwarded it to NA by letter dated January 23,
1979. 66 Jones stated in his response that his
understanding of the concerns addressed was:(1) How is decay heat removed? (2) Will systemrepressurization occur? If so, could a smaller casebe a worse break? (3) If the operator isolates thebreak, will system repressurization occur? If so,
will the pressure relief valves be subject to slug or
two-phase flow?67

Jones' response related that, although repressuri zation may occur, he disagreed that repressurization could cause a faster depletion of inventory froma very small break when compared to a larger small
break without repressurization. He used what hedescribed as a volume balance technique to explain
his reasoning. (Volume balance is a technique forunderstanding how the system responds and for
doing hand calculations. Computer models are used
by B&W to analyze specific break sizes and locations. These computer models use more complex
and mathematically rigorous relationships.)
I n addition, he agreed that two-phase flow
through the safety valves may occur, but he argued
that even if they are damaged by that flow, such an
accident had been evaluated in the Final Safety
Analysis Report and found not to be a problem.
Jones also addressed the concern about operator interpretation of pressurizer level.
In hisresponse, he stated:
As far as the appropriateness of the operator usingpressurizer level indication to trip the HPI, B&W
agrees that the level indication is not a reliable indication of the state of the RCS [reactor coolant system]. However, use of the pressurizer level indication, along with system temperature and pressure
measurements to ensure that the system is still in a
substantially subcooled state will provide sufficientguidance for operator action. 68

Jones did not feel that the problem of operators
securing high pressure injection pumps based onpressurizer level alone was a particular concern because he believed that supplemental guidance had
been provided to the operators as a result of
memos proposing further guidance, written by Keiyand Dunn earlier in 1978 69 (see Section I.C.10).
14 7

Dunn testified that in the course of reviewing
Jones' work, he recognized Michelson's concern
about operator interpretation of pressurizer level,
but believed that the issue had already been
resolved because of the guidance that he thought
had been sent to all operating B&W plants in
response to his memos. Therefore, he believed that
this concern had already been resolved for operati ng plants. Dunn also felt confident that, although
Joseph Kelly (see Section I.C.10) had not seen theMichelson report, he would ensure that new designs
would be responsive to the concerns expressed byMichelson with respect to operator interpretation ofpressurizer level.
When Michelson received Jones' response, hisi mpression was that B&W had not understood hisconcerns. He sent a letter to B&W pointing out thatuse of a volume balance was not consistent withphysical law and that some statements in B&W's
response contained inconsistencies with respect tothe application of the volume balance technique.
This letter, dated February 8, 1979,71 acknowledged
receipt of the B&W letter and stated, "TVA will require the following clarification and additional explanation to complete its review... "72 This clarification
was associated with the volume balance techniqueused by B&W. The letter requested a response by
March 15, 1979. Because of higher priority work,
Jones did not respond to this second letter prior to
the accident at TMI.
After the accident at TMI, Taylor of B&W forwarded a detailed analysis of the Michelson reportto the NRC in May 1979.73 The cover letter forwarding the analysis concluded that all of the concerns raised in the Michelson report had been addressed within the B&W evaluation mode. The report also addressed the specific question of operator interpretation of pressurizer level and stated:
Pressurizer level is not a good indication of primarysystem liquid inventory. No operator action should
be based on that signal alone. It is quite possible tohave a smaller break causing a slow loss of RCS[reactor coolant system] inventory and eventual
voiding of the reactor core while maintaining a reasonable pressurizer level if high pressure injection
is terminated prematurely. The only positive indication of reactor vessel liquid inventory is a subcooled indication of all RCS [reactor coolant system] pressure and temperature indicators excepting those in the pressurizer. This point is considered and demonstrated within the evaluation
model particularly for breaks which occur in thepressurizer itself. a

Mattson stated that the key conclusions of the NRC
staff evaluation of the Michelson report include:(1) The overallsmall
breaks was shown to behavior be for the the most plants part, consistent with the behavior as predicted by Michelson
and, within the expected accuracy the B&W
analysis substantiated Michelson's hand calculation
results. (2) This behavior did not result in unacceptable consequences and the core is not calculated to uncover for the small break accident
scenarios postulated by NA (Michelson).76
However, it should be noted that the technicalevaluation contained in Michelson's report (excluding the concern about operator actions based onpressurizer leveQ has little direct impact on the accident that occurred at TMI-2. Michelson's analysis
i s based on a 205-fuel-assembly B&W design, but
the TMI-2 plant is a 177-fuel-assembly B&W design.
Michelson has testified that, even if B&W had done
an extensive analysis and had done everything thathe could reasonably have expected to be done withrespect to his concerns about small break analyses,
such action would not have had any significant impact on the accident at TMI because of the differences between the 205-fuel-assembly plant that heanalyzed and TMI-27
Specifically, TMI and the other 177-fuel-assemblyplants are less susceptible to the problems raisedby Michelson because the auxiliary feedwater issprayed into the top of the steam generator;
whereas on 205-fuel-assembly plants the auxiliary
feedwater enters at the bottom of the steam generators. This difference greatly reduces the time required for transition from natural circulation topool-boiling. However, the concern about operator
interpretation of pressurizer level is directly applicable to the TMI accident. Jones agreed in his testi mony that, even in hindsight, the only part of theMichelson report that applies to the TMI accident is
the comment about operator interpretation of pressurizer level.78
Specific Conclusions
1. The technical issues raised in the bulk of theMichelson report are still a matter of controversy.
B&W still contends, on the basis of extensive
analyses performed after the TMI accident, that
their method of analyzing very small-break LOCAs is valid and that such accidents are boundedby the small-break analyses that they had performed before the accident at TMI. Michelson
still contends that his comments as they are applied to the B&W 205-fuel-assembly design, arestill valid and unresolved.

Furthermore, in a letter dated May 24, 1979,75
from Roger Mattson of the NRC to Henry Myers, a
special consultant to the House of Representatives
Subcommittee on Energy and the Environment,148

2. The bulk of the technical discussion contained in
the Michelson report, particularly with respect tothe issue of repressurization and increased
discharge through a very small break, did not
directly apply to TMI because TMI is a 177-fuelassembly plant and the analysis was based on a
205-fuel-assembly plant.

3. The handwritten draft report prepared by Michelson and subsequently informally provided to the
NRC contains a very limited discussion of operafor interpretation of pressurizer level. On theother hand, the typed draft contains a lengthy
discussion of the response of pressurizer level
during such a transient and the subsequent
operator actions that might result because of thisi ndication. For example, comments such as, "Afull pressurizer may convince the operator to trip
the HPI pump and watch for subsequent loss oflevel," 79 are included in the typed draft, but noti ncluded in the handwritten draft.

4. Michelson and Ebersole were painfully naive tobelieve that a handwritten draft report, informallyhanded to a first-line supervisor within the NRC,
would receive anything more than a cursory review. The lack of followup by Ebersole after heforwarded the report to Israel exacerbated the
problem of this report not being given extensive
consideration by the NRC.

5. B&W response to the Michelson report was excessively slow. However, this slow response
was due primarily to the fact that B&W believedthat the technical issues raised in the report were
not significant and were already adequately addressed in earlier analyses, and that the bulk of
their effort was associated with explaining why
the concerns raised in the report were not significantissues .

6. With respect to the issue of operator interpretation of pressurizer level, B&W felt that this issue
had been resolved by the additional guidance
that Kelly, Jones, and Dunn all mistakenly beli eved had been sent to the various utilities as aresult of the Kelly-Dunn memos.

7. Although Michelson was (and still is) a consultant
to the ACRS, he did not provide the Michelson
report to Ebersole, a member of the ACRS, because of this formal relationship (i.e., the report
was not submitted to the ACRS). Michelson andEbersole had been close personal friends long
before either of them became associated with the
ACRS. It was in this context of personal friends
who shared a common interest (i.e., small-break
LOCAs) that the Michelson report was given to
Ebersole.

149

9. DAVIS BESSE-SEPTEMBER 24, 1977
An incident occurred at the Davis Besse Nuclear
Power Station on September 24, 1977, that bears astrong resemblance to the subsequent accident at
TMI-2. The incident began at 9:34 p.m. while theplant was operating at 9% power with one effective
full power day of operation. The incident was initiated by a spurious half-trip of the steam and feedwater rupture control system. This trip stopped thefeedwater flow to the No. 2 steam generator whichcaused the level in the steam generator to decrease. At 1 minute and 16 seconds after the spurious half-trip, a full trip was initiated as a result of
low level in the No. 2 steam generator. This full trip
isolated the main feedwater flow to the other steam
generator and initiated auxiliary feedwater flow.
However, the No. 2 auxiliary feedwater pump turbine
did not come up to full speed because of binding of
the turbine governor. This situation resulted in no
auxiliary feedwater flow to the No. 2 steam generator. At approximately the same time that the full tripof the steam and feedwater rupture control systemoccurred, the pilot operated relief valve (PORV)
opened as designed. However, due to a missing relay in the control circuit, the valve rapidly cycledopen and shut, and eventually failed in the open position.
The full trip of the steam and feedwater rupture
control system also shut the main steam isolation
valves. As a result of the loss of cooling to thereactor coolant system, the reactor coolant systemtemperature increased, which in turn caused pressurizer level to increase sharply. At 1 minute and 47
seconds the operator manually tripped the reactor
because of high pressurizes level.
The tripping of the reactor, the open PORV, andthe injection of cold auxiliary feedwater to the No. 1
steam generator caused reactor coolant systemtemperature and pressurizer level to decrease. At
this point, the operators were verifying proper
operation of various safety features and responding
to numerous alarms that were received in the control room. The alarms were received so rapidly thatthe implications of each alarm could not be analyzed
i n detail. The difficulties were further compoundedby the fact that the operators did not immediately
realize that the incident had been initiated by a malfunction8oof the steam and feedwater rupture control
system.
As pressure continued to decrease, it eventuallyreached 1600 psi (at approximately 3 minutes), at
which point the safety features actuation system
actuated. The actuation caused containment isolation and initiated high pressure injection flow. The

containment isolation shut the vent on the quenchtank, which received the discharge from the open
PORV. As a result, the pressure increased in thequench tank and caused the rupture disk to blow.
The operators realized that the rupture disk had
blown. However, they thought that, at most, the
PORV had stayed open slightly longer than normal;
they did not realize that the PORV was still stuck
open.
The operators did have the computer printout oftemperature at the outlet of the PORV available;
however, they did not use that information because
the alarm printer was too far behind. 81 The only
other indication of the PORV position was from thecontrol power signal for the solenoid, and that erroneously indicated that the valve was shut.
At approximately 4'/z minutes pressurizer level
stopped decreasing and began to increase as aresult of the influence of the high pressure injection
pumps. However, reactor coolant system temperature and pressure continued to decrease. At approximately 6 minutes, the operators stopped thehigh pressure injection pumps because pressurizer
l evel had returned to normal and, in fact, had increased above the initial level. 82 Securing the highpressure injection was consistent with the plant's
emergency procedures, which stated in Emergency
Procedure 1201.06.2, Section 2.4.3, "Note that as
RCS [reactor coolant system] pressure is decreased, the HPI [high pressure injection] must be
throttled to maintain pressurizer level."S 3 However,
the action of stopping high pressure injection was
i nconsistent with the plant operating procedures,
specifically Plant Procedure 1101.01.2, Section 1.1.3,
Item 6, which states:ize that the plant was not responding as they had
expected, particularly in light of the fact that pressure had continued to decrease. Some of theoperators thought initially that this pressure decrease might be caused by overcooling of the reacfor coolant system caused by the injection of cold
water into the No. 1 steam generator, 86 however,others realized that they were losing reactor coolant
system water. At approximately 9 minutes, pressure stabilized at 900 psi and pressurizer level was
offscale high. The operators found this combination
very confusing, but they realized that the system
was saturated, and that the pressure was remaining
constant and the pressurizer level was high as aresultof the boiling in the reactor coolant sys87 88
tem. At approximately 9 minutes and 20
seconds, the operators tripped one reactor coolant
pump in each loop to reduce the heat input to thesystem. Only in retrospect did the operators realizethat securing pumps to reduce heat input was notconsistent with their concern that pressure decrease might be due to overcooling. 89
Reactor coolant system pressure remained constant for approximately the next 13 minutes, while atthe same time pressurizer level remained offscale
high. At approximately 22 minutes, the operators
received a high containment pressure alarm. This
alarm, coupled with an instrument reading of 3 psig,
caused one of the operators to finally realize that aleak was occurring from the reactor coolant system.
This fact, as well as earlier information about thequench tank rupture disk blowing and other matters
indicated to him that the PORV was open, and he
immediately shut the block valve. Shutting theblock valve while the makeup pumps were runningcaused a repressurization of the system. This
repressurization collapsed the steam bubbles that
had formed in the reactor coolant system, and pressurizer level rapidly decreased. Because of this decrease, the operators manually restarted the highpressure injection pumps.
Approximately 1 hour after the incident began, theoperators had increased reactor coolant systempressure above saturation and had returned pressurizer level to normal. As a result, they secured
the high pressure injection system a second time.
At this point, the plant was essentially in a stablecondition.

Reactor coolant system pressure must be maintained above the pressure that would allow the formation of a steam bubble at the highest point of the
36-inch reactor coolant piping. 84

I n hindsight, some of the operators were amazedthat they stopped high pressure injection based onpressurizer level indication alone, because theyrealized that the plant was approaching saturation
conditions. They can only attribute this action to
the confusion that existed in the control room. 85
Pressurizer ievel began to decrease after thehigh pressure injection system was stopped because of the continuing decrease of reactor coolant
system temperature. At 7 1/2 minutes into the incident, saturation pressure was reached in the reacfor coolant system and boiling began. The void formation in the reactor coolant system caused expansion of the water and an increase in pressurizer level. At this point, the operators were still involved
with responding to alarms and checking proper
operation of systems. However, they began to real-

Response to the Incident
NRC Office of Inspection and Enforcement,
Region 111

The NRC Office of Inspection and Enforcement(I E), Region III in Chicago was first notified of the in1 50

cident by telephone at 8:45 a.m. on Sunday, September 25, 1977, the day following the event. The
event was perceived by the Region III personnel as
being a very severe transient, but, because the plant
was in a safe condition, it was decided that it was
not necessary
to send someone to the site immedi91
ately.
The Principal Inspector for the Davis Besse
plant, Thomas Tambling, was scheduled for a training session during the week following the incident,
so another inspector, Terry Harpster was sent to
the plant on Monday, September 26.
The purposes of Harpster's trip to the plant were
to determine if the plant was in a safe shutdown
condition, determine all the relevant parameters duri ng the transient, ensure that proper analysis of thetransient was conducted, 92 and define actions
necessary before any further plant operation. 93
Harpster's review, which lasted approximately 1
week, raised several concerns that were subsequently related to Tambling. These concerns included the operator response during the transient;evaluation of the pressure excursion, including boili ng effects in the core and the effects of boiling on
the fuel; and a possible problem with the high pressure injection system due to the fact that the operators were not sure if high pressure injection had
gone into the core. 94
Harpster's concern about operator response
centered on the fact that the operators had not had
adequate training to recognize the problem with thesteam and feedwater rupture control system, particularly because this system was unique to Davis
Besse. Harpster was also concerned about the
failure of the operators to integrate plant parameters(e.g., their reliance entirely on pressurizer level).
However, he did not voice this second concern because the emphasis of his work and his major concerns were associated with plant physical probl ems. 95 Harpster also considered the generic implication of this incident; however, he thought it unreasonable to conclude that a similar transient could
occur elsewhere because of the mechanical failures
i nvolved and the fact that the steam and feedwaterrupture control system that initiated the incident was
unique to Davis Besse. 96 Harpster was subsequently involved in a training session for various
reactor inspectors and staff personnel at Region III.
This session included a discussion of the chronology of events, the initiating sequence, the operator
response, and the various equipment malfunctions.
On September 30, 1977, an immediate action
l etter97 was issued by Region III as a result of theSeptember 24, 1977 incident. Among other things,
this letter required an evaluation of the pressure excursion including boiling effects, to ensure that boiling did not cause damage to the reactor coolant

system. IE practice and policy required that thisevaluation be completed before the plant was re98,99
turned to mode 4 (hot shutdown).
When Tambling assumed responsibility for the investigation, his primary concern was resolving
100
specific items in the immediate action letter.
Tambling was aware that void formation had occurred in the reactor coolant system, but he viewed
it principally as a potential equipment problem associated with vibration of the reactor coolant pumps
and potential fuel damage. Tambling did not realizethat void formation had caused the pressurizer level
to increase; consequently, he believed that theoperator action of securing high pressure injection
was appropriate in view of the fact that pressurizer
101
l evel had returned to the operating range.
Tambling also considered the generic implications of thei ncident. However, he concluded that no generic issues were associated with the incident because thepilot operated relief valve (PORV) that had failed
open had been designed by one manufacturer, andthe valve in other B&W plants was designed by adifferent manufacturer. 102 I n addition, the fact thatthe relay in the PORV control circuit was missing
was considered a plant problem andwould not be
103
expected to occur at other facilities.
At the conclusion of his inspection, Tambling requested that the licensee prepare a supplement to
the initial Licensing Event Report (LER NP-32-771
16) 04 that would include the analyses that Tambling
had already reviewed at the105
site. This material (LER
NP-32-77-16 Supplement)
was forwarded to the
Region III office on November 14, 1977, as a part of
the report that is required within 90 days following
such incidents.
The results of Tambling and Harpster's investigalion were documented in an Inspection Report(No.
10650-346/77-32) dated November 22, 1977.
This
report describes the incident as a sudden depressurization and notes several conclusions that are
relevant to this Special Inquiry: (1) the operators
had problems discovering that the PORV was open
because of lack of direct indication of the valve's
position, and therefore, Toledo Edision installed indications of position of the PORV pilot valve; (2) the
PORV control circuit was not safety-related and notcovered by the quality assurance program forsafety-related components; and (3) B&W had
analyzed the incident and found that it was within
the scope of the generalized depressurization transient previously analyzed. As a result of this inspection, no items of noncompliance associatedwith the incident were noted.
This concluded Region III involvement with this incident until concerns about this incident were raised
by James Creswell, Region III Inspector. These con1 51

consider these concerns to be any more significant
2
than other safety concerns that came up daily.n
On October 3, 1977, Mazetis gave a briefing torepresentatives from the Division of Systems Safety
and IE including Roger Mattson, the Director of theDivision of Systems Safety, and Karl Seyfrit, the Assistant Director, Division of Reactor Operations Inspection in IE. The general characteristics of thetransient were discussed, as was the plot of pressurizer level, reactor coolant system temperature,and reactor coolant system pressure, prepared byEngle (Figure 1- 9). The conclusion of this meeting
was a decision by Seyfrit and Mattson that IE would
n3maintain lead responsibility for the investigation.
Subsequently, Mazetis prepared a note dated
October 20, 1977, from Denwood Ross of NRR to
Seyfrit. n4 The note described some areas of interest to the Division of System Safety that he believed should be addressed in the Toledo Edison
Company formal report of the incident. One concern stated:cerns are discussed in detail in Section I.C.12 of thisreport.

NRC Office of Nuclear Reactor Regulation

The NRC Office of Nuclear Reactor Regulation(NRR) also became involved with the investigation ofthis incident. Leon Engle, the Licensing ProjectManager for Davis Besse, was notified of the eventby the Office of Inspection and Enforcement. However, because IE did not request assistance, Engle
concluded that active involvement by NRR was not107
yet required.
At the same time, the Division of
Systems Safety within NRR also became aware of
the event, and a factfinding group headed by Gerald
Mazetis was sent to the plant. Engle, Mazetis, andseveral other representatives of the Division of Systems Safety met with representatives of the utility,
B&W, and Region III at the site on September 30,
1977.
Engle collected data from the incident and, after
returning to Washington, plotted this data (see Figure 1-9). Although the data plots revealed thatsteam formation had caused the pressurizer level toi ncrease, Engle did not consider this finding to besignificant. He also realized that the operators had
secured the high pressure injection system before
i solating the leak. However, he did not focus onwhether or not this action was proper because heconsidered operator action to be a responsibility of
I E. 108 His primary concern was the fact that a relay
such as the one that was found missing in the
PORV control circuit could be removed from a system without anyone's knowledge. He believedthat little action could result from this concern because the system was not considered to be a safety system. He was also concerned that the investigation was being conducted unsystematically because of the number of groups involved and thelack of coordination. He informed his supervisor ofthis concern, but nothing was done.110
After his review, Mazetis prepared a handwritten
trip report" in which he noted that saturation pressure was reached during the event and that theoperators secured high pressure injection when
they observed an increasing pressurizer level. In
this informal report, he related several issues andconcerns, including: (1) there were endless speculations associated with this event, and (2) the licensee
should address the dynamic effect of vapor formation in the reactor coolant system during the transient, particularly because it was associated withreactor coolant pump cavitation and seal effects.
This informal report may not have been distributed
to anyone. Mazetis has testified that he did not

The operator's role in participating in the event
should be related. For example, the manual actions
associated with the control of level in steam generator No. 2 should be described. The operator's
decision to secure high pressure injection flow
based on5pressurizer level indication should be explained."

Seyfrit does not recall whether he received thisnote; however, he believes that if he had received it,
he would have called Region III or sent a copy of thereport to the people conducting the investigation in
116
Testimony by Region III personnel andRegion III
a review of the Region III files failed to produce thedocument or any recollection on the part of Region
III personnel concerning the issues raised by thisdocument. The meeting on October 3, 1977, andthe October 20, 1977 note appear to be the only
forums in which the concerns raised by NRR personnel would have been forwarded to the IE inspectors conducting the investigation. The October 20,
1977 note apparently ended the Division of Systems
Safety involvement.
R.J. McDermott of the Quality Assurance Branchi n the Office of Nuclear Reactor Regulation also
conducted a review to determine if deficiencies in
the licensee's quality assurance program or test
program had caused or contributed to the transient.
I n a memo dated October 6, 1977, 117 McDermott
noted that the emergency core cooling system had
i nitiated at 1600 psig, that pressure reached as low
as 800 psig, and that boiling occurred in the reactor
coolant system. He did not comment on thesefacts. He noted that he did not have sufficient information to reach a conclusion, but that he had re1 52

1 53

quested additional information from the IE inspector.
On October 20, 1977, McDermott wrote a memo
i n which he concluded that the licensee had notbeen able to determine why or how the relay in the
PORV control circuit was removed. This memo
concluded McDermott's involvement. It does notappear that any subsequent actions were taken asa result of this review.

be reported. Seyfrit stated that the answer was a
combination of all three; but, he concluded that theperformanceat Davis Besse was not unique or123
unusual.
Seyfrit discussed this incident again at the November 1977 ACRS meeting. During the discussion,
he noted that some cavitation had occurred in thereactor coolant pumps due to boiling, but that nodamage had occurred. Ebersole again asked about
the implications of the same accident at full power.
Seyfrit again responded that the same combination
124
of events would be unlikely at full power.

NRC Office of Inspection and Enforcement,
Headquarters

In addition to the meeting on October 3, 1977,
Karl Seyfrit participated in a briefing of the Advisory
Committee on Reactor Safeguards (ACRS) on October 7, 1977 concerning this incident. During thisbriefing, it was noted that some boiling had occurredi n the reactor coolant system. However, Seyfrit
concluded that the transient was completely terminated after about 15 minutes by putting the No. 2
119auxiliary feedwater pump in manual.
This was ani nteresting observation since the PORV was still
stuck open at this time. Ebersole, who had alreadyreceived the handwritten draft of the Michelson report (see Section I.C.8) and who subsequently
prepared the Pebble Springs questions (see Section
I. C.11) asked questions during this briefing. Specifically, he asked if high pressure injection had
pumped water into the reactor coolant system.
Seyfrit's response was that it had not because theoperator had turned it off. 1 20 Ebersole also asked if
it was planned to extrapolate the event to 100%
power. Seyfrit stated that it was not likely that theplant could
be in this particular position at 100%121
Seyfrit's conclusion that the plant could
power.
not have a transient such as this at 100% power
was based on the following points: the plant was
operating by dumping steam to the condenser rather than using the main turbines; the plant was using
the startup feedwater system rather than the main
feedwater system (the spurious half-trip of thesteam and feedwater rupture control system which
i nitiated the incident would not have isolated feedwater flow to the No. 2 steam generator if the main
feedwater system had been in use); and different
systems would be in operation and122therefore wouldchange the nature of the transient.
During the ACRS briefing, Seiss, a member of the
ACRS, stated that Davis Besse had submitted what
appeared to be an abnormally large number ofli censee event reports. He offered three hypotheses; (1) the number was, in fact, abnormallyl arge for a plant startup; (2) the number was typicalof plants during a startup; or (3) Davis Besse personnel had a different interpretation of what should

B& W Response

Fred Faist is the Site Operations Manager for
B&W at the Davis Besse plant. His initial involvement with the incident began with attendance at a
meeting with Toledo Edison personnel at 10:00 a.m.,Sunday, September 25, 1977. The purpose of themeeting was to identify the recovery effort thatwould berequired and to review the sequence of125
events.
Faist subsequently requested that additional personnel be sent from the B&W offices in Lynchburg,
Va. to support this effort. Therefore Joseph J. Kelly was sent to the Davis Besse plant to assist in theanalysis of data that had been collected during theincident.
Kelly spent approximately 2 days at the plant, attempting to determine the sequence of events. Kelly did not consider what the operators saw or how
they interpreted what they saw. His understanding
was that the utility was interested primarily in assigning tasks to be accomplished before returning
plant to service, and this was the emphasis of his
26
work 1
When Kelly returned to B&W, he gave abriefing in Lynchburg to people who were later sent
to the plant to support Toledo Edison in its meetingwith the NRC.
Kelly had identified several concerns that heraised with Faist and with B&W personnel in Lynchburg. These concerns included: (1) fuel damage
because of boiling in the core; (2) reactor coolant
pump damage resulting from operation at saturation
conditions; (3) mechanical stress to the steam generators resulting from increased temperature difference associated with lost insulation; (4) chemical
damage caused by boric acid crystallization on carbon steel pipe; (5) stress associated with127
excessive
cooldown rates; and (6) the PORV failure.
During the briefing of B&W personnel in Lynchburg, Kelly discussed with Bert Dunn and Robert
Jones of the B&W staff a concern associated withthe steam formation in the reactor coolant system.
154

Dunn resolved Kelly's concern about boiling and thepossibility that it would damage the core, but raised
a new concern about the operators
incorrectly
128,129securing high pressure injection.
This led Kell y to prepare a memo concerning the guidance provided to operators
associated with securing high13°(see Section I.C.10).
pressure injection
Faist also worked on the recovery effort following
the incident. Some concerns that he identified include the following:

Toledo Edison

The involvement of Toledo Edison management
began during the actual incident. Terry D. Murray,
the Assistant Station Superintendent (Murray became the Station Superintendent in November1977), was at the plant when the incident occurred.
Murray arrived in the control room shortly after theoperators manually tripped the reactor and heremained there throughout the incident. After Murray was confident that the plant was stabilized in anormal hot shutdown condition, he telephoned thestation superintendent to inform him of the incident. 137 Murray did not contact the NRC at thisti me. 138
On Sunday morning, September 25, 1977, a
meeting of station staff and support personnel washeld to: review the details of the incident; identify
i ssues that required additional investigation; anddevelop a plan to correct physical139 damage that occurred inside the containment.
Shortly before thegroup convened, the NRC was contacted.
The principal concerns that came out of this inhouse conference were of potential damage toreactor coolant pumps and to the fuel because ofvoid formation in the reactor coolant system; thermal stress of the reactor coolant system; mechanical damage inside containment;
and the cause of14°
the sticking of the PORV.
Two or three weeks after the initial meetings
concerning the incident, the personnel who were in
the control room met with a group of consultants tothe president of Toledo Edison. During this conference the operators discussed
the information avail141,142
It was observed durable in the control room.
i ng the discussion that a common thread in these
events was theoperator's inability to recognize
143
small LOCAs.
At least one of the operators also
stated that his training had not prepared him for thisevent because he had neverseen a leak where144
pressurizer level increased.
It does not appear
that any actions were taken as a result of this meeti ng. In addition, this was the only time that theoperators were asked to describe the difficulty they
had in determining what was happening during theevent. 145• The alarm on one high pressure injection leg

cleared, but the operators did not see flow indication in that leg. (Faist believes that this occurred when the operators
manually initiated high131
pressure injection,but others believe that thisoccurred when high pressure injection initiatedautomatically early in the incident.)• Michael Derivan, the shift foreman in the control
room during the incident, was confused by thefact that pressure decreased while pressurizer
level increased. However, Faist testified that hedid not consider the possibility that other operators might subsequently be confused.32

Faist has testified that he had discussed theoperation of high pressure injection during the incident with Dunn and Jones of B&W, and they concluded the high pressure injection should not havebeen turned off because of the possibility that it
would not restart correctly if it were needed later in
133
However, it does not appear thatthe incident.
Faist did anything as a result of this discussion.
Faist prepared a Site Problem Report (No.
34
He has testified that he tried to describe372)1
the hardware problems that had occurred and thesequence of events, as opposedto opinions and in135
terviews with personnel.
Therefore, he did notrecord the fact that the operators were confused by
the indication that they saw, nor did he report thatthe operators secured high pressure injection incorrectly. He simply noted that the operators had
secured high pressure injection.
In the Site Problem Report, Faist also pointed outthat the steam and feedwater rupture control system actuation did not trip the reactor. Toledo Edison opposed installing such a trip because theywanted to keep the steam and feedwater rupture
control system and the reactor protection systemseparate. Toledo Edison personnel believed thatthe reactor protection system would trip the reactor
when required. Faist did not consider the generici mplications of the need for a similar anticipatory
trip, based on loss of feedwater, on other B&W
plants. 136

Specific Conclusions
1. The incident that occurred at Davis Besse is almost an exact copy of the accident that subsequently occurred at TMI. The reasons that Davis
Besse did not sustain the severe core damage
that resulted at TMI are that the Davis Besse
155

plant had been operating at a very low powerl evel and had a very low power history, and theoperators at Davis Besse were able to identify
and isolate the open PORV in 20 minutes as opposed to 2 hours at TMI. If it had not been forthese fortuitous conditions, it is very likely thatthe incident at Davis Besse would have been as
severe as the subsequent accident at TMI-2.
2. Numerous groups were involved with the reviewof the incident at Davis Besse; a team from the
Office of Nuclear Reactor Regulation, an individual from B&W in Lynchburg, two inspectors fromthe Office of Inspection and Enforcement, andplant personnel. Unfortunately, their efforts were
not coordinated, and consequently the concerns
raised by individuals were never exchanged
among the members of the organizations. For
example, the concerns raised by Mazetis in the
Office of Nuclear Reactor Regulation that subsequently were forwarded to the Office of Inspection and Enforcement as the Ross-Seyfrit note
were never forwarded to the IE inspectors actually conducting the investigation. Similarly, theconcerns raised by Kelly that resulted in the
Kelly-Dunn memo were never forwarded to anyone outside of the B&W organization. Becauseof this fragmented investigation, there was nevera cross-pollination of ideas, which might haveresulted in a realization of the significance ofsome of the individual concerns.

that should have been identified, and they
dismissed the generic implication of the incident
by their emphasis on the equipment failures rather than an emphasis on the overall scenario that
occurred.

6. In reviewing the incident at Davis Besse, one cansee several indications that the PORV was open
and that the reactor coolant system inventory
was decreasing. With the benefit of hindsight theoperators' actions appear to include a number of
errors. These errors include stopping the highpressure injection pumps as the reactor coolant
system approached saturation conditions and thedelay in closing the PORV block valve.

Study of the behavior of highly trained people
under emergency conditions suggests that suchpeople rarely make simple blunders in the operation of systems. Such people typically are highly
disciplined; trained to follow procedures carefully;
trained to avoid improvisation; and intensely
aware of rules and constraints. Compared withthe average person, they rarely make tactical errors in the sense of accidentally turning thewrong knob. Nevertheless, such trained people
sometimes do make errors in emergencies. To
distinguish these from the ordinary kind of errors,
we may call these "strategic" errors. In an emergency such people recognize that something iswrong and that some action must be taken.
They conceive a model or scenario for what ishappening. They follow procedures or reaction
strategy which they believe is applicable to thescenario. Studies also show that once a
scenario is conceived and a reaction strategy undertaken, there is a tendency not to seek or perceive additional data which contradict the original
scenario. There is a psychological phenomenon
called "cognitive dissonance" which makes themind tend to reject data in conflict with the original hypothesis. 146

3. All of the review groups overemphasized equipment. The reviewers tended to disregard thegeneric implications of the incident at Davis
Besse by simply arguing that the specific piecesof hardware were different in other plants. This
argument was proposed in spite of the fact thatsimilar pieces of equipment with comparable probabilities of failure and similar failure modes werei nstalled on other B&W plants and, in somecases, on all pressurized water reactors.
4. The people directly involved with the investigation
made no significant effort to assess the scenario
from the perspective of speculative analysis. Little consideration was given to what would have
happened if the plant had been at a higher power
level or a higher power history, or if it had taken
the operators longer to identify and isolate thestuck-open PORV.

After an incorrect scenario is conceived, an
entire pattern of actions can be taken which inretrospect are blunders. This phenomenon canbe seen to a limited extent during the September
24, 1977 incident at Davis Besse, and to a muchgreater extent during the TMI accident. However,it does not appear that this phenomenon has
ever been addressed in the design or licensing of
nuclear powerplants. The implications of thisphenomenon are considerable since it implies
that any sequence of actions by an operator, nomatter how ill advised it may seem to a dispassionate observer, (i.e., the designer) may in fact
be a creditable event that must be considered in
accident analyses.

5. The information concerning the incident that occurred at Davis Besse was not effectively distributed to other B&W utilities, specifically to Metropolitan Edison. However, this is due primarily tothe fact that the people directly involved with thei nvestigation of the incident did not identify thesignificant issues associated with the incident

1 56

10. KELLY-DUNN MEMORANDA-NOVEMBER
1, 1977

ditions except a normal, controlled plant shutdown.
(b) Once high/low pressure injecton is initiated, do
not stop it unless; TAVE is stable or decreasing andpressurizer level is increasing and primary pressure
is at least 1600 psig and increasing. 154

Joseph Kelly of the B&W staff in Lynchburg, Va.,
was sent to the Davis Besse plant to assist Fred
Faist, the B&W Site Operations Manager, in determining the sequence of events. Kelly's conclusions
were given previously in Section I.C.9.
Upon returning to Lynchburg, Kelly discussed thei mpact of steam formation in the reactor coolant
system with Robert Jones [who subsequently became involved with the review of the Michelson report (see Section I.C.8)] and Bert Dunn of the B&W
staff (see Figure 1-10 for the organizational relationships that existed). Dunn indicated that he did notconsider steam formation to be a particular problem,
but he did believe that the operators had terminatedthe high pressure injection system prematurely. He
pointed out that he could develop scenarios inwhich the operators could have engendered serious
consequences147,1
by securing high pressure injectionaswhen they did.
Kelly did nothing officially about Dunn's concern
until he learned of a subsequent incident at Davis
Besse on October 13, 1977 in which the operators
prevented high pressure injection initiation. Because of this second example of what he considered to be improper operator action, Kelly wrote
a memo dated November 1, 1977.149,150
Before writing this memo, Kelly talked to thesimulator instructors at B&W and they stated thatthey did not understand why the operators reacted
as they had. They stated that the operators had notbeen trained to secure high pressure injection unless reactor coolant system temperature had stabili zed, reactor coolant system pressure was increasi ng, andpressurizer level was in the indicated
151
band.
Kelly's November 1 memo noted that during the
September 24, 1977 incident, "the operator stopped
HPI when pressurizer level began 152
to recover,without regard to primary pressure"with theresult that boiling occurred in the reactor coolant
system. Concerning the October 23, 1977 incident
he wrote, "the operator bypassed High Pressure Injection to prevent initiation, even though reactor
coolant
system pressure went below the actuation
153
Because some accidents require continupoint."
ous operation of high pressure injection, Kelly wondered what guidance, if any, should be given to thecustomers on when they could safely secure thehigh pressure injection system. He recommended
some guidance that he considered to be appropriate. This proposed guidance stated:

This memo was sent to a distribution list of seveni ndividuals in the management of the B&W organization in Lynchburg. Kelly has testified that the purpose of the memo was to raise an issue and initiate
a dialogue because, although he had not reviewed
the guidance, if any, that was being given at thattime, 55 he felt uncertain, on the basis of the actionsof the operators at Davis Besse, that B&W was giving the operators adequate guidance. The only
response that Kelly received to his memo was ahandwritten memo
156 from Frank Walters dated November 10, 1977.
Walters testified that he was not actively involved
with the review of the September 24, 1977 incident
at Davis Besse and, after receiving Kelly's memo, he
conducted a superficial review of the Site Problem
Report. He did not realize that steam had formed in
the reactor coolant system, or that the high pressure injection system started automatically and was
subsequently stopped by the operators during thei nitial parts of the transient. He now asserts that, inreviewing the transients, he thought that Kelly wasreferring to a sequence of events that began approximately 30 minutes after the incident began.
During this sequence the operators manually started
high pressure injection after they had shut the
PORV block valve and then stopped high pressure
i njection when the plant had stabilized. He believed
these actions were appropriate and saw no reasonsfor Kelly's concerns. Moreover, he felt that if Kelly's
guidance was sent to the operators, there would bepossible problems with the plant going solid and potential failure of the safety valves to reset,
which
157
would cause a loss-of-coolant accident.
After reviewing the incident in more detail during
the deposition conducted as part of this Special Inquiry, Walters agreed that the securing of high pressure injection by the operators during the initial
phase of the transient was improper. He now feelsthat Kelly's concern about preventing similar improper operator action in the future is more significant than his concern about the plant going solid ifhigh pressure
injecton is allowed to continue to156
operate.
As a result of his original review of Kelly's memo,
Walters also believed the wording of the guidance
proposed by Kelly was too complicated for theoperators to understand and remember.
He
prepared a response on November 10, 1977, in
which he stated that the operators at Toledo Edison
responded correctly in view of their training. During(a) Do not bypass or otherwise prevent the actuation of high/low pressure injection under any con-

15 7

to be reinitiated. During the 20 to 30 minutes ofnoninjection flow they were continuously losing important fluid inventory even though the pressurizer
i ndicated high level. I believe it is fortunate that
Toledo was at an extremely low power and extremely low bumup. Had this event occurred in areactor at full power with other than insignificant
bumup, it is quite possible, perhaps probable, thatcore uncovery and possible fuel damage would
have resulted. (Emphasis added.)the incident at Toledo Edison there was no loss of
coolant of magnitude and, in Walters' opinion, theoperators would not be right to place the reactor
coolant system in a solid condition every time thehigh pressure injection pumps initiate.
I n addition to being confused by Walters'
response, Kelly was troubled because he had notreceived a response from anyone other thanWalters. However, he made no attempt to contact
any of the individuals involved and he did not contact Walters. Instead he went to Dunn and recommended that Dunn write a memo escalating the issue 159
Dunn's involvement had begun a month and halfearlier when he attended the presentation given by
Kelly. Dunn believed that the plant had responded
as expected, but that the operators should not havesecured high pressure injection when they did. He
had discussed this matter with Kelly and Robert
Jones and this discussion was the basis for Kelly's
memo. Dunn and Kelly realized that little happened
as a result of Kelly's memo.
In fact, Dunn believed that attention was not being paid to his concerns, and that this lack of actionwaswhich Walters was a member. However, Dunn did
not contact anyone to see why action was not being
taken 160 Instead, he prepared a memo dated
February 9, 1978,161 and sent the memo to James
Taylor. The memo was addressed to Taylor because Dunn felt that it may have involved a safetyconcern. Dunn has testified that he was prepared
to write a preliminary safety concern notification inaccordance with B&W procedures for formally raisi ng safety concerns had he not subsequently beensatisfied that his i nformal memorandum had
worked 162 Such a preliminary safety concern
would have been sent to Taylor for resolution.
Dunn's memo began with the statement, "Thismemo addresses a serious concern within ECCS
Analysis about the potential for operator action to
AnalysisHigh Pressure Injection following the initialstage of a LOCA . " 163Dunn continued,

Dunn's memorandum stated that "the incident
points out that we have not supplied sufficient information to reactor operators in the area of recovery
from a LOCA."165 Dunn also provided some specificrecommendations for changes to the guidance tothe licensees to be used in preparing operating procedures. This guidance recommended that operati ng procedures be written to allow for termination ofhigh pressure injection only under the following two
conditions:(1) Low pressure injection has been actuated andis flowing at a rate in excess of the high pressure
i njection capability and that situation has beenstable for a period of time (10 minutes). (2) Systempressure has recovered to normal operating pressure (2200 or 2250 psig) and system temperature
within the hot leg is less than or equal to the normal
operating condition (605"F to 630"F). *6
When Taylor received Dunn's memo, he referred
the matter to the Customer Service Group which hefelt could more appropriately respond to such a
concern.167 D.F. Hallman received the memo in
Customer Service and referred the issue to Walters
for resolution. Walters had the same reaction to
Dunn's memo that he had to Kelly's memo. He wasuneasy about the operators' understanding of theguidance proposed by Dunn, and the possibility ofthe plant going solid .166
Walters asked Gaslow of his staff to talk to Dunnabout rewording the precaution to make it easier forthe operators to understand. Gaslow contacted
Dunn, and they developed a wording that was mutually acceptable. After his meeting with Gaslow,
Dunn prepared a second memo to Taylor dated
February 16, 1978.169 In this memo, Dunn referenced his earlier memo and stated that Customer
Services had recommended the following procedure
for terminating high pressure injection following a
LOCA:(1) Low pressure injection has been actuated and isflowing at a rate in excess of high pressure injection capability and that situation has been stable fora period of time (10 minutes). Same as previously
stated. (2) At X minutes following the initiation of
the high pressure injection, termination is allowed
provided the hot leg temperature indication plus appropriate instrument error is more than 50'F below
the saturation temperature corresponding to the[T]he direct concern here rose out of the recent incident at Toledo. During the accident the operator
terminated high pressure injection due to an apparent system recovery indicated by high levelwithin the pressurizer. This action would have been
acceptable only after the primary system had been
in a subcooled state. Analysis of the data from thetransient currently indicates that the system was ina two phase state and as such did not contain sufficient capacity to allow high pressure injection termination. This became evident at some 20 to 30
minutes following termination of injection when thepressurizer level again collapsed and injection had
159reactor coolant system pressure less instrument
error. X is a time lag to prevent the termination of
the high pressure injection immediately following its
i nitiation. It requires further work to define its
specific value, but it is probable that 10 minutes will
be adequate. The need for the delay is that normal
operating conditions are within the above criteria
and thus it is conceivable that the high pressure injection would be terminated during the initial phasesof a small LOCA.

Dunn also noted in the memo that he found thisscheme to be an acceptable method of preventing
long-term problems. Kelly and Dunn have both testified that they believed that the issue had been
resolved and that as a result of his February 16,
1978 memo the appropriate
guidance would be for171,172
warded to the utilities.
However, Walters did
not consider that the issue was settled because therevised wording only resolved his doubts about theclarity of the guidance and did not resolve his concern about potential problems associated with goingsolid. He asked Gaslow to talk to Dunn again toresolve this second matter. However, because173ofhigher priority work, this meeting never occurred.
In August 1978, Walters wrote a memo 174 askingthat Plant Integration resolve his concern. The
memo was signed by Hallman, was addressed toBruce Karrisch of Plant Integration, and included
Dunn's February 9 and February 16 memos as
references. The memo stated, "References 1 and 2(attached) recommend a change in B&W's philosophy for HPI [High Pressure Injection]
System use
175
during low-pressure transients."
The memo also
noted that the references suggest the possibility of
uncovering the core if present HPI policy is continued. The memo went on to say that Nuclear Service (i.e., Customer Service) believed that therecommended change could cause the reactor
coolant system, including the pressurizer, to go
solid. The memo suggested that the following questions be evaluated:(1)... the pressurizer goes solid with one or more
HPI pumps continuing to operate, would there be apressure spike before the reliefs open which would
cause damage to the RCS [Reactor Coolant System]. (2) What damage would the water surge
through the relief valve discharge piping andquench tank cause?176

Hallman concluded the memo with the statement"We request that Integration resolve the issue of
how the HPI system should
177 be used. We are available to help as needed."
Although Dunn was included on the distribution ofthis memo140 he has testified that he does not recall receiving it. His explanation for this disparity isthat either he did not actually receive the memo or,
if he received
it, he did not recognize its signifi178
cance.

160

Karrisch's involvement with this matter beganwith attendance at the briefing given by Kelly. However, Karrisch does not remember the details of thei ncident. In addition, although Kelly works for Karrisch and included him on the distribution for his November 1, 1977 memo, Karrisch does not recall receiving it. He also does not recall seeing either of
Dunn's memoranda which were attached toHallman's memo. Karrisch does recall receiving
Hallman's memo and he recalls noting the two
specific questions that were asked, specifically thequestions associated with the pressure spike andwith the water surge. However, he did not noticethat the memo requested that he, representing Plant
I ntegration, resolve the issue of how the high pres179
sure injection system should be used .
Karrisch recalls sending the memo to someone
for action, but he cannot remember whom. After the
TMI accident, he talked to the two people to whom
he would have sent the memo, and they do not recall seeing it. Karrisch was contacted several times
by Hallman concerning the memo, and in early 1979
Karrisch again reviewed the memo himself. At thisti me he again did not realize that the memo requested that he resolve the broader issue of how highpressure injection should be used, but only noted
the two specific questions concerning the implications of the plant going solid. He did not review thetwo memos from Dunn that were referenced in theHallman memo. 180
When he did undertake the review of the Hallman
memo in early 1979, Karrisch recalled work that had
been done in the fall of 1978 as part of the analysisof the generic issue associated with anticipatedtransients without scram (ATWS). As part of thisstudy, considerable work had been done regarding
the implications of expected water surges throughthe safety valves. This work had shown that eventhough the safety valves and associated piping were
not qualified for water relief, water relief was an ac181
ceptable condition for those valves.
Therefore,
Karrisch did not see any difficulty associated withthe two specific questions raised by Hallman's
memo. He responded verbally to Hallman in February or early Marchof 1979 in a very short and infor182,183
mall discussion.
Karrisch believed that Hallman acknowledged that he (Karrisch) had answered
Hallman's questions. 184
Hallman recalls receiving a response from Karrisch to the effect of, "I don't think there is a problem." Later he realized that this response could beinterpreted in one of two ways: (1) issuing the guidance proposed by Dunn was not a problem; or (2)Dunn's concerns were not valid and therefore, theguidance did not need to be issued. Hallman thentried to contact Karrisch185
but was unsuccessful before the accident at TMI.

Although Kelly who started this whole sequence,
works for Karrisch, Kelly186,187
was not involved or madeaware of this exchange.
Hallman has stated that in the course of his review of this issue, he thought that Kelly and Dunn
were simply concerned that the operators had notraised reactor coolant system pressure high enoughbefore securing HPI. He did not realize that theoperators secured high pressure injection on thebasis of high pressurizer level caused by boiling in
the reactor coolant system. He has stated that if he
had recognized this fact he probably would have
escalated the issue to his superiors and pressed
Karrisch harder to resolve it. 1 88
The strong wording used by Dunn should have
impressed Hallman with its significance; but apparently it did not. Considering this strong wordingin Dunn's memo, it is hard to understand how therealization described above would have caused
more aggressive pursuit of this issue.
It must be emphasized that Kelly, Dunn, andJones have testified that they did not realize that
this exchange between Hallman and Karrisch was
taking place. The three subordinate engineers have
all testified that it was their understanding that, foll owing the February 16, 1978 memo from Dunn to
Taylor, fhe appropriate guidance was mutually acceptable to all of the parties involved and would beshortly sent to the utilities. It was not until after theaccident at TMI-2 that they found that this guidance
had not been sent. 189-191

problems had been resolved. After the accident
at TMI-2, Dunn found that these problems had
not been resolved and that the guidance he proposed had not been forwarded to the utility. A
significant point is that Kelly, Dunn, and Jones all
mistakenly believed that in early 1978, the guidance that they had proposed had been sent tothe utilities. It was not until after the accident atThree Mile Island that they found out that thiswas not correct, and that the guidance had neverbeen sent.
4. An additional breakdown of communications occurred between the Customer Services Groupand the Plant Integration Group. Customer Services forwarded a memo, unknown to Kelly andDunn, to Plant Integration requesting that theconcerns about the plant going solid and theoverall issue of how the high pressure injection
system should be operated be resolved. This
resolution never happened, and no evidence exi sts as to whom the memo was sent for action.
Eventually, Karrisch in Plant Integration did
resolve the two specific questions about the implications of the plant going solid. However, he
did not communicate this resolution to Customer
Services effectively. At no time did Karrisch realize that he had been asked to review the overall
operation of the high pressure injection systemand therefore, he did not provide a response
concerning this issue. Furthermore, he apparently did not recognize that the issue that he had
been asked to resolve had been initiated by oneof his employees (Kelly) and Kelly was everaware that Karrisch had been asked to resolve
his concern.
5. The Special Inquiry concludes that the failure of
B&W to provide the guidance recommended by
Kelly and Dunn was primarily the result of agross failure by several individuals, including Kelly
and Dunn, to communicate effectively, and ineffective management practices that resulted in thisi ssue not being adequately addressed. No evidence of a conscious effort to suppress the concerns raised by these engineers was found.

Specific Conclusions
1. Kelly and Dunn identified issues that, had they
been resolved, would have provided pertinent,
meaningful guidance to the operators at TMI-2
and might have prevented them from taking theactions that ultimately resulted in substantial
damage.
2. A lack of communication may have existed
between Kelly and Dunn on the one hand, andvarious members of the Customer Services
Group at B&W on the other. As a result, a crucial
misunderstanding regarding precisely what
operator actions had caused Kelly's and Dunn'sconcerns may have developed and was neverresolved. Consequently, representatives of the
Customer Service group and the Plant Integration
Group continued to debate the merits of theoperator actions, when, in fact, it appears they
may have been talking about two entirely different sets of operator actions.
3. On one occasion, Dunn and a representative of
the Customer Service group, did meet to discuss the concerns, and Dunn understood that the

11. PEBBLE SPRINGS ACRS QUESTIONSNOVEMBER 1977

161

I n November 1977 Jesse Ebersole of the NRC
Advisory Committee on Reactor Safeguards (ACRS)
prepared a set of 26 questions that were eventually
forwarded to the Portland General Electric Company
for response during the ACRS review of the Pebble
Springs application. Three questions are relevant tothis Special Inquiry because they were either related

to the TMI accident or they were based on theMichelson report, which Ebersole had received in
September 1977, or both (see Section I.C.8). These
questions were forwarded to the NRC staff by a192
memo dated November 7, 1977.
The memo forwarding these concerns began with a statement
that, "attached are questions raised by an ACRS
member, to which the Pebble Springs subcommittee
would like written responses prior to the ACRS full
193
Committee review of that project."
The first.question that is relevant to this Special
I nquiry was based on the Michelson report. The
question, number 6, stated:

tric by letter dated November 21, 1977. 199 The
responses to the questions, which were preparedby B&W for Portland General Electric Company,
were provided to the staff for subsequent forwardi ng to200
the ACRS by letter dated November 30,
1977.
These responses, which total approximately 52
pages, (less the 10 pages required to restate thequestions) were prepared in less than 10 days. The
response relative to question 6 included approximately three pages that detailed how the reactor
coolant system would react during the transients
described. This analysis concluded that uncoveringof the core would not take place, and therefore thei ssue was not a problem. The pressurizer is not
mentioned in this response, and the question relati ng to "What does operator do in respect to interpreting level in pressurizer?" 201 was not addressed.202
Bert Dunn of B&W, who prepared the response
to question 6, testified that he had had a continuing
discussion of these general issues associated withsmall breaks with Ebersole. In his approach toquestion 6, he attempted to respond to his understanding of Ebersole's general concerns, rather thanresponding to the specific questions asked. He did
not realize that he had not responded to one of thequestions, the question associated with operator in203
terpretation of pressurizer level.
Dunn also testified that he did not connect
Ebersole's question about operator interpretation ofpressurizer level with the issues that he and Kelly
had raised about securing of high pressure injection
by the operators during the Davis Besse incident on
204
September 24, 1977(see Section I.C.10).
When the questions ' and responses were received from B&W through Portland General ElectricCompany, they were reviewed by Scott Newberryof the NRC's Reactor Systems Branch. He testified
that he perceived that he was responsible to be
familiar with the material and to discuss the
responses at the ACRS meeting. He did not review
the response to question 6 in detail because he feltthat any questions associated with small breaks
would be addressed by Sanford Israel (also of the
NRC's Reactor System Branch), who was the staff
member who customarily responded to questions
205
about small-break LOCAs.
With respect to the other questions that are
relevant to this Special Inquiry, the response toquestion 12 stated:

Does applicant know that time-dependent levels will
occur in pressurizer, steam generator and reactor
vessel after a relatively small primary coolant breakwhich causes coolant to approach or even partly
uncover fuel pins? What does operator do inrespect to interpreting level in pressurizer? [ Emphasis added.]
During primary system refill from high pressure
injection pumps there is some period when neither
condensation nor natural convection is present toeffect heat transport to secondary side. How istransition to natural convection without assistancefrom primary coolant pumps obtained . 194

The second question based on the Michelson report is question 12, which stated:

What is status of investigation of merits of a primary vessel coolant level indication system for use
i n post LOCA cooling for small breaks? 195

The third relevant question is not directly related
to the Michelson report but is related to the accident at TMI. This question, number 26, asked:

Considering such matters as (1) offsite power
failure, (2) condenser vacuum failure, (3) spurious
main feed water valve closure (see Item 21 preceding) and recent incidents of failures in auxiliary feedwater system it appears that, single failure criteria
notwithstanding, at least short term failures of theauxiliary feed water system must be considered toestimate the needed availability of such system.
What, for instance, would be the peak primarysystem pressure, consequences to primary coolant
system safety and relief valves and rate of primarycoolant loss following failure of the Auxiliary Feedwater pumps when needed?196

These questions were initially distributed to the
NRC staff by the Division of Project Management in
NRR with a request that written responses be provided to the licensing project manager no later thanNovember 30, 1977, for possible incorporation into aformal reply.197,198

B&W is no longer considering the use of primary
vessel coolant level indication systems. Present
analyses show that adequate system protection isprovided by existing equipment and sensor design.
For the specific case of small breaks in the primarysystem, please note the response of Question 6. 206

It was subsequently decided that rather than having the staff prepare responses, the questions
would be forwarded to the applicant for the Pebble
Springs license, Portland General Electric Company.
The questions were sent to Portland General Elec-

1 62

For question 26, the answer concluded that the
Pebble Springs design complied with the latest NRC
requirements. However, a preliminary analysis of
the event sequence assuming that all feedwater was
l ost simultaneously was provided. The significant
points in this scenario were as follows: at approximately 10 seconds into the event the pressurizer
begins to relieve decay heat by way of the safetyvalves; at approximately 2 minutes the reactor
coolant system expansion causes the pressurizer tobecome water solid; at approximately 10 minutes thehigh pressure injection initiates as a result of highcontainment pressure; and at approximately 45
minutes high pressure injection heat removal equals
decay heat removal. However, boiling does occur inthe core, but stops before the end of the postulated
scenario (i.e., at approximately 45 minutes). A coolable geometry is maintained throughout and thel ong term cooling is provided by the high pressure
i njection system. 207
After the responses from Portland General Electric were received, a meeting was held within the
NRC to decide on the staff's position. A firm technical stand was not taken because the applicant's
analysis was not provided in detail; therefore, thestaff felt it could not review the work in detail. The
staff did not feel that they had the responsibility toreview the responses to the same extent as if thequestions had been originated by the NRC staff
rather than by the ACRS. Furthermore, some of thequestions went beyond what the staff would normally require
in its review (e.g., more than a single
20s
failure).
Consequently, the responses were forwarded to the ACRS without comment.
The responses were subsequently discussed at afull ACRS committee meeting in January 1978. Duri ng this meeting, Ebersole noted that the parties involved had done a good job and had been responslue to the questions asked. 209 A lengthy discussion of the various questions was conducted which
i ncluded specific reference to question 6. Ebersole
again raised the issue of how the operators would
i nterpret pressurizer level. The initial argument wasthat this subject would be covered in their training.
However, Ebersole stated that he thought this event
would not be accurately simulated by the simulator
used for operator training. This assertion was notchallenged by any individual at the meeting. No
subsequent discussion of this issue was conducted,
2lo
and the meeting proceeded to the next question.
The NRC representatives involved with this ACRS
meeting generally do not recall the discussion ofoperator interpretation of pressurizer level. Theiroverall impression was that the ACRS discussion
did not raise any concerns. In addition, they
presumed that the response satisfied Ebersole, sothey did not carry the issue any further. Because
the emphasis of the NRC review is on design ofsystems, the reviewers normally do not review what
the operators see or do, and are generally not concerned with how the012
operator would interpret certain plant conditions.
This situation may explain
why the NRC staff did not recognize this issue.
Representatives of B&W were also in attendanceat this ACRS meeting, but the concern about operafor interpretation of pressurizer level was not identified by B&W's internal review of issues raised duri ng ACRS meetings as an issue requiring further
analysis. This oversight is probably due to the factthat throughout the licensing process, the emphasis
at B&W has also been on the design analysis andengineering aspects. Items related to the operator
and the operating procedures do not get the samelevel of attention within B&W as items related to213system design.
Ebersole testified that he realized during the
ACRS meeting that he had not received an answer
to his question about operator interpretation ofpressurizer level. He did not make a major issue of
this fact. He took comfort in the fact that he had
exposed the issue to all the participants at the
ACRS meeting. Furthermore, he knew that Michelson was pursuing the matter separately withBMW 214
As is its normal practice, the ACRS in January
1978 wrote a letter to the Chairman of the NRC
describing
its review of the Pebble Springs applica215
tion.
This letter did not cite any of the 26 questions or responses as outstanding items requiring
additional review. The letter did cite the Portland
General Electric response as a reference and notedthat the 26 questions had been raised by Ebersole
and responded to by Portland General Electric. The
letter also noted that Steve Varga of the NRC staff
had said that the NRC found nothing
in the216
responses to alter the staff's conclusions.
The Atomic Safety and Licensing Board for Pebble Springs also raised the issue of the ACRS questions in a prehearing conference on April 12, 1978.
A specific question was:Has the staff reviewed the November 30, 1977
applicant's response to a series of questions raisedby the ACRS? Are there any unresolved questions
at this time? Can construction proceed pending a
resolution? Are all of them included in the staff's
list of unresolved items? 217

1 63

I n its reply, the NRC staff stated that they had reviewed the applicant's responses and found nothingthat would change the evaluation as recorded in the
Safety Evaluation Report and the four supplements.
The staff noted that the majority of the questions
had sought additional clarification of specific items

of interest, and some posed assumptions andscenarios that exceeded those criteria necessary
for the protection of the health and safety of the
public. The staff concluded that they agreed withthe applicant that the system was designed in accordance with NRC requirements. Finally, the reply
to the licensing board noted that the January 12,1978 letter from the ACRS indicated that the Committee was satisfied with the applicant's responses
including additional information provided by the staff
and applicant at the Pebble Springs ACRS review
meeting. 218

However, the responses were not mentioned in
the body of the ACRS letter, and no indication
was given that any of the issues raised, either inthe questions or in the responses, required further evaluation.

12. CRESWELL CONCERNS-DECEMBER 1977
Throughout 1978 and 1979, an IE Region III inspector, James Creswell, raised concerns associated with the Davis Besse nuclear powerplant that
had some relevance to the accident at TMI-2.
Creswell's involvement with Davis Besse began inAugust 1977. He was assigned to inspect the facility during startup and was subsequently assigned toi nspect its power ascension program. Creswell,
however, was not the Principal Inspector for Davis
Besse at any time. The portion of Creswell's involvement with Davis Besse that is relevant to thisi nquiry began following an incident at Davis Besse
on November 29,1977.
While preparing for a test with the plant operating
at 40% power, the operators plugged a reactimeter
patch panel into the plant's instrumentation system.
Because of a short circuit in the panel, the unit
demand signal was shorted and produced an erroneous demand signal of 62.5%. Power started toramp from 40% to 62.5%, but the reactor tripped as
designed at 50% power. When the reactor tripped,
the turbine automatically tripped. Because of an error in the plant procedure, the operator tripped thegenerator output breakers. The generator output
breakers would have tripped automatically 30
seconds after the turbine tripped. Because the output breakers were manually tripped rather than automatically tripped, house power loads were not automatically transferred to offsite power. This situation resulted in a total loss of ac power in the station, which tripped the reactor coolant pumps andstarted the diesels. One diesel operated properly
but one tripped on overspeed. After the reactor
coolant pumps stopped, the plant was cooled using
natural circulation. Subsequently, power was restored and the plant was returned to normal operation.
This incident was reviewed by the NRC Office ofI nspection and Enforcement, the B&W organization,and the Toledo Edison organization. The B&W personnel at the plant describedthe event in Site Prob219
lem Report No. 396.
However, no significant issues were raised. Toledo Edison's principal concerns centered on the error in the procedure thatallowed the operator to trip the generator output
breakers rather than waiting for the automatic trip,

Specific Conclusions
1. Two of the three questions that are relevant tothis Special Inquiry, were prepared as a direct
result of Ebersole's review of the Michelson report (see Section I.C.8).
2. Although the questions were specifically addressed to the staff, the staff chose to send thequestions to the utility for response. The utility
subsequently sent the questions to B&W, andB&W eventually prepared the response that was
forwarded to the ACRS.
3. Question 6 was actually a collection of several
questions. B&W attempted to respond to theiroverall perception of Ebersole's concern about
the small-break LOCAs rather than trying to
respond to the specific questions that wereasked in question 6. Consequently, one question, "What does operator do in respect to interpreting levels in pressurizer?" was not recognized
by B&W and was not answered. This deficiency
was not noted by either the applicant (Portland
General Electric Company) or by the NRC staff intheir review of the responses.
4. Ebersole discerned that the question about
operator interpretation of pressurizer level had
not been answered in the formal response provided. Therefore, he asked a related question
during the ACRS full committee meeting on Pebble Springs. Ebersole still received an unsatisfactory response, but he did not pursue thematter because he felt that he had adequately exposed the issue in the written questions and in
the ACRS full committee meeting.
5. The NRC staff and the B&W staff that attended
the meeting did not identify the issue of pressuri zer level and operator interpretation as warranti ng additional evaluation. Thus, this concern ended at this point and was never subsequently
raised.
6. The ACRS letter for Pebble Springs cited the
responses prepared by B&W as a reference.
164

and on the reason for the failure of the diesel generator. In IE Inspection Report 50-346/77-34, 220
the conclusions were that (1) the incident wascaused by a short in the patch panel; (2) the loss ofoffsite power was due in part to procedure inadequacy and operator error; (3) the diesel generator
tripped on overspeed; and (4) the temperaturepressure transient was reviewed by B&W who concluded that it was bounded by existing analyses.
In December 1977, Toledo Edison raised the possibility that the November 29 incident might be usedin place of a required natural circulation test. Thispossibility was considered by B&W; however, B&W
concluded that the data were incomplete and they
could not approve the transient as a satisfactory
test of natural circulation. 221
Toledo Edison subsequently requested that the
NRC consider the possibility of using the data fromthe November 29th event in place of the natural circulation test. A meeting was held with the NRC on
February 7, 1978 to discuss this issue. Toledo Edison argued that although the data did not specificall y meet the requirements of the natural circulation
test, the 3 days at low power required to conduct
the test were not justified by the benefits to begained because the elevated steam generators at
Davis Besse would produce more flow than that observed at an earlier
natural circulation test at the222
I n a letter from the NRC on
Oconee Plant.
February 16, 1978 223 , the conclusion was that thenatural circulation test must be run at Davis Besse,but Davis Besse was allowed to proceed to 100%
power with the condition that the test be conductedwithin 120 days.
Because of the Toledo Edison request, the Principal Inspector for Davis Besse, Thomas Tambling,
asked Creswell to go to the site and review the data
to determine what the IE Region III position was withrespect to its adequacy. When Creswell arrived at
the site, he requested the plot of various parameters
during the transient and found that a plot of pressurizer level was not provided. He requested thatplot and subsequently received it. This plot showedthat pressurizer level had gone offscale low forsome period of time during the event. Consequently, he asked that calculations be done to determine
the minimum pressurizer level that existed during
the incident because he was concerned that possibly the pressurizer had emptied during the event. In
early March 1978 he received calculations fromToledo Edison that indicated that the pressurizer
had not completely emptied and that the actual levelin the pressurizer was 9 inches below the lowest
range of the pressurizer level indication (this lowest
level indication is approximately 75 inches above
the bottom of the pressurizer).
165

Creswell was concerned that the pressurizer level decrease would necessitate securing the heaters
i n the pressurizer and this action would make pressure control in the reactor cooling system more difficult. Moreover, the loss of level indication would
make it difficult for the operators to determine thereactor coolant system inventory, and the actual
emptying of the pressurizer would result in void formation in the reactor coolant system. 224
Creswell was also concerned that under worse
conditions, the results of this particular transient
could have been more severe. The specific conditions that he believed could exacerbate the situation
were: (1) both auxiliary feedwater pumps shouldhave come on simultaneously during the incident(one auxiliary feed pump did not come up to fullspeed because of mechanical failure in the governor
and therefore did not inject cold water into one of
the steam generators for several minutes during theactual event) (i.e., the incident would have been
more severe if the plant had responded as
designed); (2) the plant could have been at a higher
power level, a situation that would have caused agreater amount of decay heat to be put into thereactor coolant system; and (3) the steam generator
safety valves that normally lift during an event suchas this could have caused the steam generator
pressure to decrease even further (such a decrease
would result in a greater cooldown of the reactor
coolant system and a greater contractionof the225
reactor coolant system inventory).
Creswell reported his conclusions in an Inspection Report(No. 50-346/78-06) dated April 20,
226
1978.
He concluded that the November 29 event
did not meet the requirements for natural circulationand noted that NRR had reviewed this issue andagreed by letter dated February 16, 1978. He also
noted that pressurizer level indication had gone
offscale low for approximately 5 minutes. He statedthat the licensee later provided an analysis thatshowed that the pressurizer level fell to approximately 9 inches below the lowest level indication.
Creswell continued to pursue the issue of pressuriz-.
er level because of his concern that the transient
might have been worse under different conditions
and because he was not sure whether the incident
had been
conservatively bounded by existing227
analysis.
While Creswell was discussing this issue withToledo Edison, additional discussions of this issue
were carried on between Toledo Edison and B&W
and internally within both organizations. As early as
November 1976, B&W had forwarded a letter 228 toDavis Besse that included specific recommendations for avoiding pressurizer offscale-low indication.
These recommendations included (1) raising thenominal pressurizer level, (2) readjusting the steam
generator safety valve blowdown, and (3) raising thepressurizer low level alarm. Following the incident
on November 29, 1977, Toledo Edison had begun toaddress possible actions that could be taken toprevent the loss of pressurizer level during such an
event. One possibility, leaving the makeup pumps
on during a loss of offsite power, was recommended
229
That
i n a memo dated December 16, 1977.
memo also noted that B&W had been consulted withrespect to this matter to determine if Toledo Edison
was maintaining too high a level in the steam generators. This memo also made an interesting observation that at no time during the event did steam
generator pressure go high enough to lift the steam
generator safety valves. This comment is inconsistent with discussions elsewhere that excessive
blowdown by the steam generator safety valvescaused the overcooling and contraction of the reactor coolant system and the excessive reduction ofpressurizer level. Internal B&W memos, including
one dated February 10, 1978, 230 noted that decreasing pressurizer level offscale low was indicative of steam generator level increases due to auxiliary feedwater. This memo described this effect as
undesirable and noted that conversations with Fred
Miller of Toledo Edison indicated Toledo Edison's
desire to have this situation corrected.
I n late 1977, Toledo Edison revised its operatingprocedures on the basis of natural circulation test
results and instructed the operators to maintain thesteam generator level at 35 inches. In late 1978,
however, B&W recognized that this corrective action was improper. Toledo Edison's desire to
reduce steam generator level for maintenance of indicated pressurizer level conflicted with B&W's needto maintain a steam generator level of at least 120
i nches because that was the lowest level that B&W
felt could be maintained based on the small-break
LOCH 231
analysis. By memo dated November 28,
Toledo Edison notified IE Region III that1978,
they had identified the procedure change that could
have led to steam generator level in violation of thesmall-break LOCA analysis. Specifically, Emergency Procedure 1202.26 directed the operator to takeaction to maintain steam generator level below 120
inches even if a small break occurred. This memo
noted that a procedure was being revised. This fact
was also reported to lE232
Region III in LER 78-115 dated December 8, 1975.

The eventual solution to this problem of low pressurizer level was a dual level setpoint that would
maintain 35 inches in the steam generators during
events other than a LOCA and 120 inches during a
LOCH. B&W and Toledo Edison agreed that the

proposed solution would allow safe operation
233
This solution
without safety analysis violations.
was formally submitted to the NRC (NRR) by letter
dated December 11, 1978. 2
During this period, Creswell continued to pursue
his concern about loss of pressurizer level. In amemo from Creswell to his 235
supervisor, John
Streeter, dated August 14,1978,
Creswell recommended that during a subsequent meeting between
the Davis Besse management and the IE Region III
management, an issue that should be discussed
was the need to complete technical evaluations in ati mely manner. As a specific example, Creswell cited the loss of pressurizer level conditions
discovered early in 1978.
During this period, B&W was conducting additionanalyses
to address the issues of loss of presal
surizer indication and voiding of the pressurizer. In
a report dated August 31, 1978, "Dynamic Performance of the Pressurizer
During Reactor Trip at
236
Davis-Besse 1,"
the conclusions were that thel oss of pressurizer level indication would occur if thesteam generator pressure decreased to 950 psig,
and the emptying of the pressurizer would occur if
steam generator pressure decreased to 850 psig.
However, the report noted that the minimum expected steam generator pressure for future reactor trips
would be 980 psig. This minimum pressure washigher than the pressure experienced during theNovember 29, 1977 event because the steam generator safety valves had been adjusted to a higher
minimum pressure as a result of that event. This report indicated that during the November 29 event,the level in the pressurizer was 32 inches below thelowest level indication, which was considerably
below the original estimate of 9 inches below thelowest indication. However, this level was still 43
inches above the bottom of the pressurizer.
The report stated that, to limit steam generator
pressure during this event, the rate of fill of thesteam generators with auxiliary feedwater must be
controlled by the operator. The maximum fill rateshould be limited to 850 gallons per minute insteadof the existing 1200 gallons per minute that occurred during the November 29 event.
Creswell discussed these analyses with Toledo
Edison on September 8, 1978. 237 Creswell noted
several matters based on these analyses. First, he
was concerned because the minimum pressurizer
l evel during the November 29 event was found to be
not 9 inches but 32 inches below the lowest leveli ndication as a result of new calculations; andsecond, he was concerned that the people performing these calculations seemed to be unable topredict the actual minimum pressurizer level accu166

rately. He also felt that the analysis should have assumed no makeup flow because makeup flow would

mendations by Creswell and Streeter. By January
1979 the wording of this note had evolved to read:be lost in a loss of offsite power. 238 These revised
calculations were subsequently prepared and given
to Creswell during an inspection beginning on October 31, 1978. 2
Because of his review and interest in the November 29 event and his concern about voiding of
the pressurizer and saturation conditions in thereactor coolant system, Creswell attempted todetermine if any events had occurred at Davis
Besse in 24owhich voiding or saturation had actuallyoccurred.
I n late summer of 1978, Creswell reviewed the analyses of the September 24, 1977 incident at Davis Besse (see Section I.C.9) during
which saturation conditions had occurred in thereactor coolant system. Creswell noted that theoperators had secured the high pressure injection
pumps while the loss-of-coolant accident continued.
He considered this operator action to be improper,
and he discussed this matter with several people,
i ncluding Fred Miller of Toledo Edison's engineering
staff, and Streeter, his supervisor at IE Region 111.241
This problem of the operators securing the highpressure injection was documented in Inspection
Report No. 50-346/78-27 dated October 25, 1978,
which was based on an
inspection by Creswell on
242
September 5-8,1978.
I n this report it was notedthat the licensee was reviewing the operator actionof blocking the safety features actuation system
logic and securing high pressure injection before
discovering the cause of the loss of reactor coolant.
Apparently Miller and Streeter shared his concerns. Miller and Streeter separately discussed thismatter with Terry Murray,
the Station Superinten244
dent at Davis Besse.24a,
I nitially, Murray did notagree that the operators had performed incorrectly,
and he argued that their actions were proper because pressurizes level was increasing. However,after some discussion it was decided that a change
i n the procedures for operation of the high pressure
i njection system at Davis Besse should be made.
This change was subsequently reviewed by the Site
Review Board on September 15, 1978, and the decksion was made to change the procedure.245 A
Temporary Modification Request for Emergency
Procedure 1202.06, Section 2.4.3, was subsequentl y approvedby Toledo Edison on November 14,
246
1978
This change included a note which stated,"Prior to securing high pressure injection, insure thata leak does not exist in the pressurizer such as asafety valve or an electromagnetic relief value stuck
open." 247 These changes
248.249 were reviewed byStreeter and Creswell,and the wording was
subsequently modified based on additional recom-

NOTE: Prior to securing HPI, insure that a leakdoes not exist in the pressurizer such as a safetyvalve or an electromagnetic relief valve stuck open.
A minimum decay heat flow of 2800 gpm is required prior to securing HPI. If the leak has beeni solated, the HPI Pump can be shutdown after RCS
ppump r increases above the shutoff head of the

Unlike other B&W plants which have HPI pumps
with a shutoff head above the safety valve set point,
the shutoff head of the HPI pumps at Davis Besse isapproximately 1700 psig.
Although the issue was resolved at Davis Besse,
the generic implications of this issue were never addressed. There is no evidence that any of the parties involved proposed that the amplification in theDavis Besse procedure should be referred to otherutilities, to B&W, or to the NRC headquarters.
Creswell continued to be actively involved in his
separate concern about low pressurizer level during
the November 29, 1977 event. In early December
1978, in a phone conversation with a Toledo Edisonstaff member, Streeter was informed that under certain worst-case conditions it was possible to cornpletely void the pressurizer during a loss of feedwater event. This information was contrary toStreeter's and Creswell's perception of previous
statements by Toledo Edison to the effect that,
under worst-case conditions, the pressurizer could
not void during a severe cooldown event.251,252 Because of this new information, Creswell prepared amemoStreeter to Streeter's supe2 sor,
Gaston Fiorelli,through , dated December 19, 1978,
inwhich Creswell stated his concern about the performane of Davis Besse because of the possibility ofvoiding the pressurizes and noted that this new information raised the spector of an unreviewed safety issue. He requested that an investigation be conducted. The memo stated:
I feel that the NRC should conduct a thorough investigation of this matter to determine when the issue of pressurizer voiding was first identified, whoi dentified it (B&W or TECo) and if the issue wasproperty reported per the requirements of Part 21.
I n addition, the licensee's performance regarding
any corrective action associated with the issue
should be examined in light of regulatory requirements. 254

I n 255
a separate memo to Streeter on the samedate,
Creswell noted that it still required an inordinate amount of time for Davis Besse to complete
technical evaluations, and that this lack of timely
evaluation could result in unsafe operation. Creswell recommended in this memo that a course of167

action be developed to resolve this problem and it
be conveyed to Toledo256
Edison. Streeter requested
and Creswell provided on
on December 20, 1978257
a list of specific examples doJanuary 29, 1979,
cumented in inspection reports of failures on thepart of Toledo Edison to provide timely evaluation oftechnical issues.
Streeter subsequently initiated an investigation of
Creswell's concerns and assigned Joel Kohler andJames Foster from IE Region III to conduct the investigation. Creswell had indicated to Streeter that
he wanted to participate actively in the investiga .
258
Streeter has testified that he decided, howtion.
ever, that he wanted a more objective review of thei ssues by individuals who had not been actively involved in earlier reviews. 259
At the same time, Toledo Edison and the NRC
Office of Nuclear Reactor Regulation had been discussing a dual level setpoint that was designed tominimize or prevent problems with loss of pressurizer level indication and voiding of the pressurizer.
The dual level setpoint was formally proposed to
NRR in a letter dated December 11, 1978. 2 Thel etter concluded that the proposal did not involve an
unreviewed safety question because the 120-inch
steam generator level was only required for asmall-break LOCA, and the 35-inch steam generafor level was required to maintain pressurizer leveli ndication during transients in accordance with General Design Criterion 13.
The information provided by Toledo Edison to the
NRC concerning the dual level setpoint was supplemented by an additional analysis provided in a letter
dated December 22, 1978. 261 This supplemental
analYsis included a consideration of the transient
analysis
resulting from the inability of the operator to control
steam generator level at 35 inches. This December
22, 1978 letter concluded that, during a loss ofoffsite power with no makeup flow, the pressurizer
level would be slightly above the outlet to the surge
line; however, during a loss of feedwater, the pressurizer would empty andthe high pressure injection
262.
The supplemental analysis
system would initiate
stated that any steam voids that entered the reactor
coolant system would not collect and no flow blockage would occur because forced flow would continue. This letter concluded that there were no unreviewed safety questions associated with this is-

Although there is considerable confusion as toexactly what was reviewed and what was concluded by NRR, it would appear that within IE it was beli eved that NRR considered that voiding of the pressurizer
during overcooling events was not a prob265,266
lem.
This perception does not appear to be entirely
consistent with NRR's actual conclusions. Seymour
Weiss, whose branch in the Division of Operating
Reactors (NRR), reviewed the dual level setpoint,
has testified that if it had been at all conceivablethat the licensee could empty the pressurizer, thatwould have constituted an unreviewed safety issue.
However, Weiss has also testified that it was his
understanding that although there would be a lossof level indication with the dual level setpoint installed, the pressurizer would not empty. He has
also testified that his branch reviewed the analysis
supporting
this conclusion and found it to be267
correct.
It would therefore appear that NRR Gonsidered voiding the pressurizer to be an unreviewed
safety issue but in the case of Davis Besse andevents such as the November 29, 1977 incident, thiswas a moot point because of the proposed dual
level setpoint.
On January 8, 1979, Creswell prepared a memo
i n which he requested that information be conveyed
to licensing boards for certain plants (Midland
and268
SeveralDavis Besse) still under licensing review.
i ssues were raised in this request. The issue
relevant to this Special Inquiry stated:

I nspection and Enforcement Report 50-346/78-06
documented that pressurizes level had gone offscafe for approximately five minutes during the No29,1977 loss of offsite power event. There
are some indications that other B&W plants may
have problems maintaining pressurizer level indications during transients. In addition, under certain
conditions such as loss of feedwater at 100%
power with the reactor coolant pumps running thepressurizer may void completely. A special
analysis has been performed concerning this event.
This analysis is attached as Enclosure 1. Becauseof pressurizer level maintenance problems, the sizi ng of the pressurizer may require further review.
Also noted offsca le(l e than event was the fact that Tom
wentle (less han 520°F). I n addition, it wasnoted that the makeup flow monitoring is limited tol ess than 160 gallons per minute and that makeup
flow may be substantially greater than this value.
This information should be examined in light of therequirements of General Design Criterion 13.m

263

sue.
At a conference call on December 23, 1978,
representatives of the NRR, IE, B&W, and Toledo
Edison concluded that no fuel damage would result
from the issue raised in this matter. Therefore, they
concluded that this matter
did not constitute an un264
reviewed safety question.

Creswell has testified that he requested thisboard notification in the hope that either the licensi ng board or a technically competent intervenor
group would pick up on the issues that he hadraised and address them in the forum of a licensing
168

board hearing. 270 These matters were subsequently reviewed by IE, which decided that they did not
warrant reporting to the licensing board. 271 However, Creswell insisted272
that the matter be referred to
the licensing board
and, in accordance with IE
procedures, the matter was forwarded on273
March 29,
1979, the day following the TMI accident.
Tracing the path of Creswell's board notification
begins with his preparation of the Board Notification
request on January 8, 1979. IE Region III forwarded
the request to IE274
headquarters by memo dated
January 19, 1979.
This memo noted that IE Region III did not know the significance of the information as it may have affected staff positions, but they
believed that NRC policy required that the information be forwarded to appropriate licensing
boards.
275
By memo dated February 28, 1979,
NormanMoseley (IE headquarters) informed Dudley Thompson (IE headquarters) that based on his preliminary
evaluation, including discussions with Creswell, theitems in Creswell's request did not meet the criteria
for board notification. Despite this, Moseley noted
i n his memo that IE Manual, chapter 1530 requiredthat the information be forwarded to the licensing
boards if, as was the case here, the originator of therequest persisted in his desire to have the material
forwarded. Moseley also agreed to provide a written evaluation of the items contained in the request
276
within 7 days. By memo dated March 1, 1979,
Thompson forwarded the request to Domenic Vassallo (NRR, Division of Project Management) for
determination of the applicability of the items contained in the request. Vassallo forwarded the package to Edward Christenbury (NRC, Office of the Executive
277Legal Director) in a memo dated March 6,
1979.
Vassallo noted that the material should be
forwarded to the licensing boards immediately, to befollowed later by any technical analysis that became
available.
Vassallo also recommended that the original listof boards to which Creswell requested that the
package be sent (i.e., Davis Besse and Midland), be
expanded to include other B&W plants (i.e., Erie,
Greene County, Pebble Springs, TMI). The package
was received by Joseph Scinto (OELD) on March 6,
1979. Because of higher priority work, however, thematter was not reviewed until March 21, 1979. On
March 23, 1979, Creswell called Scinto to inquire
about the status of the request. As a result of thiscall and discussions at a subsequent staff meeting,
Scinto decided to forward the package to thelicensing boards as soon as possible. The preparation of the package for distribution to the licensing
boards, including the extensive service list associated with each of these cases, required approximately
16 9

278

one week.
Consequently, the material was
eventually sent279
to all of the parties involved on
March 29, 1979.
Considering that Creswell's request passed
through at least five different individuals in three different NRC Offices, and considering that none ofthese individuals appeared to consider the matter tobe particularly significant or time sensitive, it is not
surprising that it took almost 3 months for
Creswell's board notification to reach the licensing
boards. This is not to say that this labored journey
through the system is acceptable; however, the factthat it did continue to move through the systemdoes appear to indicate that there was no specificeffort to suppress the material contained in theboard notification.
Part of the material eventually sent to the licensi ng boards, was an evaluation by the IE headquarters' staff of each issue raised by Creswell. 280
With respect to the item that is relevant to thisSpecial Inquiry (i.e., loss of pressurizer level low),
the evaluation noted that the event had been reviewed by NRR with no unreviewed safety questions
remaining. The IE evaluation concluded that the factthat Tcold went offscale low was not a problem because of the wide range of instrumentation provided, and makeup flow instrumentation was not a deviation in the General Design Criteria because lackof indicated flow above 160 gallons per minute was
not a significant factor. The IE evaluation concluded
that loss of pressurizer level indication low could beconsidered to be a deviation from General Design
Criterion 13. However, the evaluation stated thatproviding level indication that would cover all anticipated occurrences might not be practical. The
evaluation also noted that the Davis Besse Final
Safety Analysis Report discussion of General
Design Criterion 13 listed the pressurizer level instrument, but did not mention loss of pressurizer
l evel indication during transients. The memo concluded that this apparent omission in the Safety
Analysis281 Report would be the subject of further review.
While Creswell prepared this board notification,
Kohler and Foster continued their investigation of
Creswell's concerns. They met with Creswell on
December 29, 1978 and again on January 29, 1979
i n an effort to clarify Creswell's concerns. Kohler
and Foster have both testified that they found it difficult to communicate with Creswell and could. notdetermine precisely
what it was that he wanted
282,283
them to investigate.
On the other hand, Creswell testified that Kohler
and Foster did not have the technical expertise in
B&W system interaction to understand his concernsmeetings. Anderson has testified that, during a
break in the meeting, he had a private conversation
with Kohler and Foster, during which Kohler statedthat Creswell was a troublemaker and they (Kohler
290
Kohlerand Foster) were there to "shut him up."has testified that although he does not recall making
the comment, he does not deny that he could havemade such a comment. However, he has testified
that if he made such a comment it was in the context that they were there to resolve Creswell's concerns one way or another, without any prejudgments about whether his concerns were valid. 291
Foster also did not recall the specific comment, but
he agreed with Kohler that if such a comment was
made, it was in the context that they would either
prove that Creswell's concerns were not valid orcollect the evidence
required to substantiate his292
concerns formally.
Foster and Kohler concluded that Toledo Edison
and B&W had performed a timely evaluation andthey concluded that the evidence indicated that
Toledo Edison had contacted B&W shortly after theincident to determine if corrective actions could betaken to minimize the possibility of losing pressurizer level indication, and B&W had performed ananalysis of a loss of pressurizer indication (at Arkansas Nuclear One in 1975) before the incident oc293
curred at Davis Besse on November 29, 1977.
These conclusions were documented in Inspection
294
Report No. 50-346/79-06, dated April 25, 1979.
Kohler and Foster had two meetings with IE
management upon returning to the regional office.
The first meeting on March 5, 1979 was held primarily to give IE management the initial conclusions
resulting from the investigation. A subsequentmeeting on March 16, 1979 included Creswell. The
purpose of the second meeting was to determine
whether any items of noncompliance were associated with the issues investigated. The conclusion wasthat no items of noncompliance were associatedwith the issues investigated, although some concerns were discussed with the licensee at a subsequent management meeting.
Kohler and Foster felt that Creswell was disappointed that they had not found something of more
substance in their investigation. Creswell questioned several things that Foster did not295
consider tobe within the scope of the investigation.
Apparently the slow response by Toledo Edison
to Creswell's concern, which led to his frustration
associated with this issue, was caused by a combination of several factors: Toledo Edison did notconsider Creswell's concern to be a significant
safety296
issue, but primarily an operational inconveniand there was considerable tension
ence;completely. They discussed both the issue of lossof pressurizer level indication and voiding of thepressurizer. Creswell believed that they understood
the loss of pressurizer level indication issue, but hewas not confident that they understood the more
complex voiding issue. In addition, although he did
not request that Kohler and Foster conduct a techni cal evaluation of the B&W analyses, he has testified
that he would have expectedthat such an evalua284
tion would be performed.
Kohler and Foster have testified that they beli eved that their principal responsibility was to determine if a timely evaluation of this matter had been
performed by B&W. They believed that the technical issues associated with loss of pressurizer leveli ndication and voiding of the pressurizer had been
resolved by the NRR during December 1978.
Therefore, they limited their investigation primarily tothe issue of the timeliness of 285,286
the evaluation of lossof pressurizer level indication.
Foster and Kohler went to the Davis Besse plant
to meet with B&W and Davis Besse personnel.
They also went to B&W offices in Lynchburg, Va.,
for a meeting on February 14, 1979, to discuss theconcern 109
associated with loss of pressurizer level indication.
During this meeting, Kohler and Foster
were provided with a letter from B&W to Arkansas
287inPower & Light Company, dated April 3, 1975,
which B&W analyzed an event during which there
was a momentary loss of pressurizer level indication
following a reactor trip. The letter concluded thatmaintaining reactor coolant system pressure above
1500 psig by automatic high pressure injection actuation would ensure that the reactor core remains
covered. A qualitative analysis in the letter indicatedthat even if the pressurizer emptied, reactor coolant
system pressure would drop to saturation (1000 to
1300 psig) and high pressure injection would initiate.
Kohler and Foster were also given informationthat indicated that B&W had informed Davis Besse
by letter dated November 22, 1976, 2 that a loss ofpressurizer level indication was a possible result of
the operation of the plant. The letter included a
specific recommendation to adjust the steam generator safety valve blowdown point. This recommendation had not been implemented at Davis
Besse prior to the November 29, 1977 incident, but
was implemented subsequently.
Other information given to Kohler and Foster indicated that Toledo Edison had begun investigatingcorrective actions to minimize the possibility of losi ng pressurizer level indication as early as February
1978. 289
Donald Anderson of the IE Region IV office also
participated, to a limited extent, in the Lynchburg
170

fied that they planned to request that the IE Performance Appraisal Team be sent to Davis Besse assoon as possible to assess the performance of that307
facility.
The Commissioners have testified thatthey proceeded in a less than direct manner so as
not-to publicize the fact that Creswell had talked
with them,in order to protect him from any potential
308,309
reprisals.
Creswell also discussed the issue of shutting
down Davis Besse with James Keppler, the IE Region III Director, on March 22, 1979. At this meeting,
he recommended that the Davis Besse plant be shut
down because of their 31°,311
poor management organization and performance.
Keppler felt that thisaction was premature until less drastic courses ofaction had been used to improve the performanceat Davis Besse. He believed that, for example, more
frequent and higher level management meetings,
such as those that had been used at Commonwealth Edison concerning the Zion plant, might
be usedto improve the performance at Davis
312
Besse.
However, Creswell did not expect that
this type of action would be effective because thei ssues that had been discussed with Davis Besse at
previous management meetings 313,314
had not, in his opini on, been satisfactorily resolved.
These meetings with Keppler and with Commissioners Ahearne and Bradford essentially completed
Creswell's involvement with these issues prior to the
TMI accident. After the accident at TMI, Davis
Besse was the subject of the extensive review andanalysis associated with the lessons learned fromthe TMI accident, and the assessment of the potential impact of continued operation of all B&W reactors.

between Creswell and people at Toledo Edison due
to a failure to communicate. 297
During this same time period, Creswell had also
become concerned about the overall operation of
the Davis Besse facility. He had become convincedthat Davis Besse should be shut down because of
the weakness of the Davis Besse management. Because of these more general concerns, Creswell decided that it was necessary to contact the NRC
Commissioners directly in accordance with theCommission's "open door" policy. Therefore, hecontacted
Commissioner Bradford on February 27,298
1979 299 and Commissioner Ahearne on March 12,
1979.
Shortly after his phone conversation with Commissioner Ahearne, Creswell forwarded a large
package of material documenting his concerns to
Commissioner Ahearn's office. In a summary, Creswell listed several issues relevant to this Special Inquiry. These include: (1) evidence that the B&W
reactor design provides significantly less protection
than other PWR designs (Creswell cited the Rancho
Seco March 20, 1978 incident (see Section I.C.14)
and the Davis Besse November 29,
1978 incident
300(2) numerous(see Section I.C.15) as examples);significant operator errors had occurred at Davis
Besse (Creswell cited the September 24, 1977 incident at Davis Besse as an example because theoperators shut off the emergency core cooling system during a LOCA); 301 and (3) serious questions
about conformance of B&W reactor design withseveral general design criteria (specifically, withrespect to Criterion 13, Creswell cited the November
29, 1977 event as an example becausepressurizer302
l evel indication was lost for 5 minutes).
Creswell met with Commissioners Ahearne andBradford and members of their staff on March 21,
1979 in Bethesda, Md. and recommended that Davis
303
Besse be shut down.
The Commissioners did
not wish to reach a conclusion about the merits of
Creswell's concerns until they had heard the other304
However, they realized thatside of the story.
Creswell was sincere in his concerns and that hehad come to them because he had a technicaldisagreement with his management. They also reali zed that he was concerned that his emphasis of305
these issues was adversely affecting his career.
On March 29, 1979, Commissioner Ahearne sent amemo" to Harold Denton, Director of the Office of
Nuclear Reactor Regulation, and to Davis of the Office of Inspection and Enforcement, requesting astatus report on various issues associated with
Davis Besse. These issues were based on the concerns raised by Creswell.
Commissioners Bradford and Ahearne have testi-

Specific Conclusions
1. The thrust of Creswell's concerns pertained to atechnical issue, loss of pressurizer level low in
B&W plants, as illustrated by a November 29,
1977 transient at Toledo Edison's Davis Besse
reactor, that was not directly related to the accident at Three Mile Island on March 28, 1979. It
was this issue that Creswell persisted in having
submitted to the licensing boards. In the courseof pursuing these concerns at Davis Besse,
Creswell also recognized that operator action
terminating HPI during a separate transient at
Davis Besse on September 24, 1977, had been
i mproper. This latter operator action terminating
HPI was a precursor of the TMI-2 accident.
2. During the September 24, 1977 incident at Davis
Besse, the operators secured high pressure injection 4 to 5 minutes into the transient because
171

of high pressurizer level. Creswell reviewed thisaction in September 1978 during his review of theNovember 29, 1977 Davis Besse transient. He
correctly viewed the action as improper. As theresult of the efforts of Creswell and his immediate
superior, Streeter, revised procedures for operators at Davis Besse were developed in November
1978 by Toledo Edison to prevent premature termination of HPI. Neither the matter of this operafor error nor the change in the operators' instructions at Davis Besse were reported to NRC
Headquarters as a generic problem by Creswellor by the IE Region III management or flagged forother plants. Creswell did cite the improper
operator action in material he submitted to Commissioners Ahearne and Bradford, not as an outstanding issue but as an illustration of what hefelt was the incompetence of the utility at Davis
Besse. The aspect of the September 24, 1977
transient that was a precursor of the TMI-2 accident, improper operator action terminating HPI,
was not the focus of Creswell's presentation to
the Commissioners. He did not identify this particular operator error to the Commissioners as apotential generic problem, but only as an isolated
error.
3. Creswell did focus on the safety implications ofloss of pressurizer level low during overcoolingtransients. It is still a matter of technical controversy whether loss of pressurizer level indicationand voiding of the pressurizer are significant
safety issues. In any event, neither situation occurred at TMI-2 during the March 28, 1979 transient, which involved pressurizer level indication
offscale high and a full pressurizer resulting fromentirely different phenomena. In other words, theconcern about pressurizer level falling too low
was not directly related to the misleading pressurizer level high that played an important role in
the TMI-2 accident. The two concerns are distinctly different. Creswell himself has testified
that he does not consider the issue of low pressurizer level during the November 1977 event andthe issue of operator actions during the September 1977 event to be directly related.
4. With respect to Creswell's efforts to present his
concerns about loss of pressurizer level low andabout the competence of Toledo Edison's
management at Davis Besse to his own management, the licensing boards and to the Commission we conclude:. Despite the fact that Creswell's management
disagreed with the substance of his concerns,
there was no effort to suppress or restrict
Creswell's board notification request. All of172

the procedures were followed which permit ani ndividual to bring such a concern to theboards in the face of management's disagreement with such concerns.
. The inability of the parties involved to resolve
Creswell's concerns short of escalation to theli censing boards and to two Commissioners
was the result of a technical dispute, exacerbated by personality conflicts and difficulties incommunications.
. Although the steps in the processing of board
notifications are probably appropriate, the timefor each step should be drastically reduced. A
maximum number of working days to accomplish each step (3 to 5 seems sufficient)should be fixed and enforced.
13. ISRAEL-NOVAK NOTE-JANUARY 10,1978
On January 10, 1978, Sanford Israel of the Reacfor Systems Branch, NRC Office
315 of Nuclear Reactor
Regulation, prepared a noteto the members of
the branch for signature by the Branch Chief, Thomas Novak. The note stated that loop seals in thepressurized surge line were used in some plantdesigns, particularly B&W designs. Although these
seals are not considered to be a problem during ordinary situations, under certain conditions such as
an accident where significant voids are formed in
the reactor coolant system, the result could be a
two-phase mixture in the pressurizer that was not at
the highest temperature in the reactor coolant system. Under these circumstances, additional loss ofreactor coolant system inventory or shrinkage in thereactor coolant system might not be indicated bypressurizer level.
The note pointed out that the situation had already occurred at Davis Besse when a relief valve
stuck open (see Section I.C.9). The note also provided a limited technical discussion of how thismanometer effect would function in the loop seal of
the surge line. The note concluded that,
Although the safety analyses do not require determination of the makeup system, operators would
control makeup flow based on the pressurizer levelas part of their normal procedures. As a result,under certain conditions where the pressurizer
could behave as a manometer the operator could
erroneously shut off makeup flow when significant
void occurs elsewhere in the system or loss of inventory is continuing.

Two courses of action were recommended: (1)"the basis for the design requirement be studied
carefully for all CP [construction permit] reviews

with the object of determining if the loop seal can beeliminated," and (2) "for OL [operating license] reviews procedures should be reviewed to ensure
adequate information
before the operator terminates317
makeup flow."
Israel has testified that he cannot recall precisely
why he wrote the note but he cited three possible
reasons, individually or in combination: (1) the
response of pressurizer level to voids formed in thereactor coolant system during the incident at Davis
Besse on September 24, 1977 (see Section l.C.9);(2) the draft Michelson report that he had received(see Section I.C.8); or (3) the response to the Pebble Springs questions that had been reviewed by his
318
branch (see Section I.C.11).
The note was not sent to the NRR Division of
Operating Reactors (DOR), which had technical review responsibility for plants already in operation.
Israel has testified that he had not paid much attention to the distribution of the note and was aware of
no set policy in this area. His recollection is that thefact that the note was not sent to DOR was not the319
result of a conscious decision.
Although this note was written before the operati ng license for TMI-2 was issued, Israel testified thatthe active review of the TMI case had been completed in this area and, therefore, he would not haveexpected the note to be implemented on TMI-2.
Israel did not, at the time, consider this subject a
serious problem, and the note was simply a remi nder to the individuals in the Reactor Systems
Branch to evaluate this issue on the cases that they
reviewed. He still does not believe that the concern
relates directly to the early phases of the accident
at TMI-2 because the loop seal was not whatcaused the pressurizer level to increase initially. 320
Later in the TMI-2 accident, when the pressurizer
level remained high despite the fact that the reactor
coolant system was essentially filled with steam, themanometer effect described by Israel could haveoccurred.
Novak believed that the issue was significant
enough to be brought to the attention of the reviewers and he therefore agreed that a "review remi nder" such as this note should be prepared. This
"review reminder" was essentially investigatory, andafter more information was obtained from case reviews, a decision could be made whether this mattershould be pursued further. He has also agreed thatthe matter was not referred to DOR because no one
considered whether the note should be sent to
DOR.
The only case under active review where thenote could have been applied before the TMI-2 accident was the Midland operating license applica-tion. However, requests for additional information
sent to the applicant after the note was prepared do
not include any questions that could have resulted
from this note. The reviewer involved, Scott
Newberry, testified that he does not know why thequestions were not sent, although he does recall receiving the note. The only explanation that he canprovide is that either "it fell through the crack," possibly because it had to do with operating procedures which were not normally reviewed, or hedecided to wait until a later stage of the review process, possibly because the operating
321procedures
had not yet been written for Midland.
Therefore,
it appears that no action was taken with respect tothe concerns described in this note, and that thematerial was never reviewed to determine if additional guidance should be provided to the licensees
for plants already in operation.
Specific Conclusions
1. We could not determine why Israel wrote thenote. Apparently the reason was some combination of the incident that occurred at Davis Besse
on September 24, 1977; the handwritten draft
copy of the Michelson report that was provided
to Israel by Ebersole; or the questions that wereasked during the ACRS review of the Pebble
Springs operating license application.
2. The technical content of the Israel-Novak note
did not describe the phenomenon that caused
the reactor operators at Davis Besse, and subsequently at TMI-2, to secure high pressure injection. However, the note did describe aphenomenon that may have caused the pressurizer to remain full of water during the latter stagesof the TMI accident when the reactor coolant
system was essentially completely converted to
steam.
3. No actions were taken within the Reactor Systems Branch, the branch to which the note wasaddressed.
4. The note was not sent to the Division of Operating Reactors for evaluation of its applicability tooperating plants, apparently because of an oversight, rather than the result of any conscious decision not to send it.
14. RANCHO SECO-MARCH 20, 1978
On March 20, 1978, an incident occurred at the
Rancho Seco nuclear powerplant when an operator
dropped a light bulb into an instrument panel, short17 3

ing out a nonnuclear dc power supply. This shortcaused a reactor trip and a rapid cooldown at approximately 300°F per hour. This rapid cooldown
was greater than the cooldown rate limits permitted
i n the technical specifications for the plant. Furthermore, the loss of the dc power supply caused thel oss of approximately two-thirds of the temperature,pressure, flow, and level signals available to theoperator in the control room. During the incident,high pressure injection actuated at 1600 psig which
maintained pressure above 1400 psig.

On June 20, 1978, a meeting held at Rancho
Seco included representatives from NRR and from
SMUD to discuss the cooldown transient. One purpose of the meeting was to determine whether otherfailures or initiating events could cause a similartransient.
Conflicting reports exist concerningwhether an additional failure mechanism was identified. One summary of the meeting indicated thatnone of the attendees postulated another mechanism or failure that would initiate a similar transient. 326 However, another summary of the same
meeting stated, "The final item on the agenda was a
discussion of other possible mechanisms for causi ng a severe cooldown transient. Depressurization
due to a faulty electromatic relief valve [PORV]
or
327
safety valve was the only possibility discussed."
Regardless of what was actually decided at themeeting, because of perceived higher priority work,
further action on this entire issue was suspended
after this meeting, and no additional actions weretaken on any of the issues addressed in the transfer
of lead responsibility. 328,329
As already noted, B&W had also reviewed thisi ncident and, on August 8, 1978, sent a letter toeach of the Site Operations Managers (except at
TMI-2) for subsequent forwarding to B&W plants.
This letter discussed the severe thermal transientthat had occurred at Rancho Seco and also discussed the substantial loss of nonnuclear instrumentation associated with the loss of electrical
power. The letter observed further that need for acareful evaluation of operator training and emergency operating procedures for any loss of nonnuclear instrumentation. The letter emphasized thatthe operator's response should be keyed to certain
variables if a loss of normally available instrumentation occurs. The specific variables cited as significant were (1) pressurizer level, (2) reactor coolant
system pressure, (3) steam generator level, and (4)steam generator pressure. The letter stated, "Thepressurizer level and reactor coolant system pressure assure that the reactor coolant system is filled;
the steam generator level and pressure assure adequate decay heat removal." 330
As stated earlier, this letter was sent to all B&W
utilities except Metropolitan Edison, the operator of
TMI-2. The reason this letter was not sent to TMI isthat an earlier incident had occurred at TMI on April
23, 1978, and it was thought by B&W that this issue
had been discussed with TMI in sufficient detail that
it was not necessary to send them the letter. However, no specific documentation concerning these
discussions was found. Another reason for notsending the letter to TMI was that the TMI integrated

The event was reviewed by B&W and by the Sacramento Municipal Utility District (SMUD) and it
was determined that the plant could return to power322
and that no significant damage had occurred.
However, the NRC staff noted that although nostructural damage occurred, if the plant had operated for a longer time with the associated irradiationof the reactor vessel, more significant damage waspossible as a result of brittle fracture associatedwith the rapid cooldown rate. The conclusions werethat positive steps should be taken to prevent transients of this kind, and that the generic implicationsof the transient be promptly reviewed. This review
was initiated in a memo from Darrell Eisenhut of the
NRR staff to Victor
Stello of the NRR staff, dated
323
March 30, 1978.
SMUD pointed out an additional problem, namely,that the incident had resulted in a loss of a significant amount of instrumentation, and consequently,
the operators were hampered in their attempts to
respond to the incident. This problem was caused
not only by the erroneous indications observed by
the operators, but also by the fact that the equipment responded in some cases to the erroneous
signals that were received as a result of the loss of
power. The operators found it difficult to determine
which of theirindicators were valid and which were324
i ncorrect.
This incident was also reviewed by IE, and a formal transfer of lead
responsibility was executed on
325
April 25, 1978,transferring responsibility forseveral issues from IE to NRR. The issues raised inthis transfer included: (1) review of the power supply to nonnuclear instrumentation to determine
whether design changes were necessary; (2) reviewof the advisability of automatic initiation of auxiliary
feedwater flow by a safety features actuation system signal; and (3) evaluation of the susceptibility of
B&W plants to other initiating events or failures that
could produce similar cooldown transients. Thistransfer of lead responsibility did not address theissue of the operator interpretation of indication or
the availability of indication to the operators.

174

control system involved in the response to theerroneous indication was different from the systemi nstalled at Rancho Seco. 331 If this letter had been
sent to TMI-2 it might have resulted in operator
training that emphasized the need to consider reactor coolant system pressure, and not just pressuri zer level, when attempting to determine reactor
coolant system inventory.

This matter was reviewed by B&W and the conclusions were that B&W agreed with the concept of
having the valve fail shut on loss of nonnuclear instrumentation, and that the indication of the PORV
position should be provided in the control room;
however, this indication was to come from thepower to the-solenoid.
This issue was also reviewed by the architectengineer, and an engineering change memo was initiated on April 6, 1978 . The engineering changememo provided for an indication in the control roomof power to the solenoid. The memo initially included a provision for changing the PORV to fail shut onl oss of power; however, that provision may havebeen subsequently deleted because it was not re335
quired for proper system operation.
Whether the
PORV was eventually changed to fail shut on loss ofcontrol power was not determined. Burns and Roe
also concluded that, even though it would require achange to the Final Safety Analysis Report, thechange was not an unreviewed safety question. 336
These actions were subsequently reported to the
I E Region I office by Metropolitan Edison in a letter7
dated June 27, 1978. This letter concludes thatreactor coolant system pressure reached as low as
1173 psig during the event and that (1) the control
signal should be changed to cause the valve to failshut on loss of control power, and (2) position indication for the PORV should be provided in the control room.
During this period, Daniel Sternberg of the IE Region I office also became concerned as a result of
this incident. Sternberg was the Acting Branch
Chief for the IE branch responsible for TMI-2. He
prepared a memo to IE Headquarters, dated March
31, 1978 , in which he noted that the March 29,
1978 incident resulted in a blowdown because the
PORV opened on a loss of electrical power to thecontrol bistable. Although Sternberg acknowledgedthat the valve was not safety-related, he stated:

Specific Conclusions
1. The incident itself was not a direct precursor of
the TMI-2 accident (i.e., the incidents themselves
are not similar).
2. A letter was prepared and forwarded to various
B&W utilities. The letter discussed the fact thatreactor coolant system pressure and pressurizer
l evel were the measures of reactor coolant system inventory. Had TMI-2 received this letter, it
might have resulted in additional emphasis andtraining at TMI-2 with respect to the fact thatpressurizer level alone was not an accurate indication of reactor coolant system inventory. Thel etter was not forwarded to Metropolitan Edison,
however, because B&W concluded that the issues contained in the letter had been discussedwith them during the review of a similar incident
which had occurred at Three Mile Island on April
23, 1978. This discussion is not, however, amatter of record at either B&W or Toledo Edison.
15. THREE MILE ISLAND-MARCH 29,
1978/STERNBERG MEMORANDUM-MARCH
31, 1978

On March 29, 1978, a reactor trip occurred at
TMI-2 as a result of the loss of a vital bus. Powerto the vital bus was lost because of the tripping of
the alternate power supply during a test. This lossof power caused the PORV to fail open on loss of
power to the control bistable, causing a depressurization of the reactor coolant system. Furthermore,
the high pressure injection system initiated. The
depressurization was stopped after about 4 minutes
by reenergizing the vital bus from its alternate
power supply.
The utility noted that there was a problem associated with this incident because the PORV opened(rather than closed) on loss of power to its control
bistable. In
a Startup Problem Report dated March
332
30, 1978,the utility suggested either changing
the valve to fail shut or providing an indication on
the control panel that the valve had an open signal.

It is requested that the adequacy of the design approach (i.e., valve failing open on loss of control
power) be reviewed on an expedited basis for B&W
facilities in general and Three Mile Island in particular.

Sternberg has testified that he was concerned
because the PORV failed open on the loss of a single power supply, and this failure resulted in an initiation of an unannunciated loss-of-coolant accident . Sternberg believed that his ability tocorrect problems such as this was significantly impaired since the item was not defined as a safetyrelated component. 341
Nonetheless, he thoughtthat the issue should be addressed. He also testi17 5

fled that he would have recommended that thematter be referred to NRR for review, but he had
been told earlier in his career in IE Region I not tomake such recommendations because such deci342
sions were the prerogative of IE headquarters.
Sternberg received a response from IE head3
quarters signed by Karl Seyfrit on May 3, 1978.
The response, which was prepared by Roger Woodruff, stated:

an analysis of the implications of a valve that cancause a small loss-of-coolant accident by failingopen on a loss of control power. Because of perceived higher priority work, however, Sternberg did
not pursue the issue347
after he received the memofrom IE headquarters.
Although Seyfrit did not personally review thematter in detail, he thought that because the issue
was addressed as part of the application, and thatapplication had been reviewed by NRR previously,
the design was acceptable. 348

The request is based on failure of the valve in the
open position. Failure in this position is covered inconclude that
Section 7.4.1.1.6 of the FSAR. We
344
additional review is not warranted.

Specific Conclusions

Section 7.4.1.1.6 of the FSAR, titled "Pressurizer
Control," states, "In the event that the relief valve
were to fail in the open position, pressure relief
could be controlled by cycling (open and close) the346
relief isolation valve."
Woodruff did not contact anyone in NRR about
this matter because he thought that the issue hadalready been reviewed by NRR. Furthermore, he
did not think the valve should be safety-related because the code safety valves, which provide relief
protection if the PORV fails to open, are safety346
related.
Sternberg has testified that he accepted the
response as adequate because someone had reviewed the issue and decided that it was not a
problem. However, he would have preferred to see

1. The memo is a precursor to the TMI-2 accident
because it refers to an incident that occurred at
TMI (March 29, 1978) during which a PORV failed
i n the open position creating a small LOCA.
Although this failure, was due to a loss of control
power, it had the same effect as the failure, forwhatever reason, a year later.
2. A reexamination by NRR of the adequacy of thedesign of the TMI-2 PORV, might have precipitated an assessment of the implication of a stuckopen PORV, or might have provided the impetus
for an adequate PORV position indication in thecontrol room. Such a reexamination never occurred.

176

REFERENCES AND NOTES
24'Letter from I.D. Green, Babcock & Wilcox, to T. D.
Murray, Davis Besse Nuclear Power Station, Subject:
Power-Loss to Nonnuclear Instrumentation and Suggested Operator Education, dated August 9,1978.
2
Letter from H. Dopchie, Association Vincotte, to C. K.
Beck, AEC, Subject: Possible Inadequacy of ECCS Protection Against Break of Vapor Line on Pressurizer, dated
April 27,1971.

NRC, "Reactor Safety Study-An Assessment of
Accident Risks in U.S. Commercial Nuclear Power Plants,"
Main Report, WASH-1400 (NUREG-75/014), at 79,
October 1975.
25
Rasmussen dep. at 33 (Pres. Com.).
14. at 15.
1d. at 22.
28
NRC, "Reactor Safety Study - An Assessment of
Accident Risks in U.S. Commercial Nuclear Power Plants,"
Main Report, WASH-1400 (NUREG-75/014), at 79,
October 1975.
28
27

3/d4

Anderson dep. at
20.
Letter from H. Dopchie, Association Vincotte, to C. K.
Beck, AEC, Subject: Subsequent Inquiry of ECCS Protection Against Break of Vapor Line on Pressurizer-Two
Additional Problems, dated June 25,1971.
6
Letter from C. K. Beck, AEC, to H. Dopchie, Association Vincotte, Subject: Verification of ECCS Adequacy,
dated September 13, 1971.
7
Letter from H. Dopchie, Association Vincotte, to C. K.
Beck, AEC, Subject: Possible Occurrences While in Hot
Standby with Containment in Purged Condition, dated
October 14, 1971.
8
Memorandum from C. K. Beck, AEC, to Task Force
Members, "H. Dopchie (Belgium) Inquiry on ECCS Protection Against Break of Vapor Line on Pressurizer,"
November 8, 1971.
9
Letter from A. Giambusso, AEC, to H. Dopchie, Association Vincotte, Subject: AEC/Westinghouse Confirment
Against Possible Core Exposure, dated September 28,
1972.
10 Anderson dep. at 13-18, 22-28.
11
McAdoo dep. at 13-18.
12J. P. Lapatlle, R. Galletly, and T. Cecchi, "Technical
Report on Beznau Unit One Incident of August 20, 1974:
TG-1 Trip/Reactor Trip/Safety Injection Actuation," Westi nghouse Electric Corporation, Brussels, Belgium (September 1974).
13
Anderson dep. at 13.
"Westinghouse Electric Corporation, "Safety Analysis
Report," Amendment 1, at 15.3-8, October 1972.
15
Anderson dep. at 14-15.
told. at 19.
17
Westinghouse Electric Corporation, "Safety Analysis
Report," Amendment 1, at 15.3-8, October 1972.
*McAdoo dep. at 32.
19 Letter from H. J. Faulkner, NRC, to F. Weehuizen,
Eidg. Amt. Fur. Energiewirtschaft, Subject: Additional
I nformation Pertaining to Incident at NOK-1 Nuclear Power
Plant on August 20,1974, dated June 26,1979.
528

Rasmussen dep. at

ld. at 24-25.
31
1d. at 19.

30

26-28 (Pres. Com.).

32

The Risk Assessment Review Group, "Risk Assessment Review Group Report to the U.S. Nuclear Regulatory Commission," at vi, USNRC Report NUREG/CR0400, September 1978.
33k1.
34

NRC, "NRC Statement on Risk Assessment and The
Reactor Safety Study Report (WASH-1400) in Light of the
Risk Assessment Review Group Report," January 1979.
35

C. Michelson, "Decay Heat Removal Problems Associated with Recovery from a Very Small Break LOCA for
B&W 205-Fuel-Assembly PWR," Tennessee Valley
Authority, September 1977.
38

14. at 30.

371d. at 9.

Ebersole dep. at 10.
Michelson dep. at 22.
40
Ebersole dep. at 17.
41
lsrael dep. at 28, 31.
42
Mazetis dep. at 25.
43
1srael dep. at 26-47.
44
Mazetis dep. at 25.
45
Michelson dep. at 24.
46
C. Michelson, "Decay Heat Removal During a Very
Small Break LOCA for a B&W 205-Fuel-Assembly PWR,"
Tennessee Valley Authority, January 1978.
38

39

471d.
48

49
50

14. at 4.6.
1d.

1d. at 4.6.
Michelson dep. at 28-29.
52 Letter from D. R. Patterson, Tennessee Valley
Authority, to J. McFarland, Babcock & Wilcox, Subject:
I ncreased Interest and Questioning by ACRS in Reference to Very Small Break LOCA's, dated April 27, 1978.
51

20
Letter from T. M. Anderson, Westinghouse Electric
Corp., to R. L. Tedesco, NRS, Subject: Westinghouse's
Guidance to Plants Having the Coincident Low
Pressurizer/Low Pressurizer Level Safety Injection, dated
August 20,1979.

53

Michelson dep. at

34.

"Letter from D. R. Patterson, Tennessee Valley
Authority, to J. McFarland, Babcock & Wilcox, Subject:
I ncreased Interest and Questioning by ACRS in Reference to Very Small Break LOCA's, dated April 27, 1978,
at 3.

21 NRC, "Reactor Safety Study-An Assessment of
Accident Risks in U.S. Commercial Nuclear Power Plants,"
Main Report, WASH-1400 (NUREG-75/014), October
1975.
221d. at 63, 79.
23
Rasmussen dep. at 14 (Pres. Com.).

55
58

17 7

Lightle dep. at 13-16.
1d. at 16,18-19.

57
58

59

Michelson dep. at 34.
Lightle dep. at 16.

Jones dep. at 26.
60
Memorandum from H. Bailey, Babcock & Wilcox, toF. J. Levendowski, "Small Break Report," May 25, 1978.
6%. at 1.
82
Ad. at 2.
83
Babcock & Wilcox Telecopy of C. Michelson's Summary "Small Break LOCA Analysis."
64/d.
65Id

Letter from J. McFarland and R. E. Lightle, Babcock& Wilcox, to D. R. Patterson, Tennessee Valley Authority,
Subject: B&W Response to Michelson's Report, dated
January 23, 1979.
671d. at 2.
88
Id. at 3.
69
Jones dep. at 52.
70
Dunn dep. at 47-48.
71
Letter from D. R. Patterson, Tennessee Valley
Authority, to J. McFarland, Babcock & Wilcox, Subject:
Request for Clarification and Additional Explanation Pertaining to Small Break LOCA Analysis, dated February 8,
1979.
721d. at 1.
73
Letter (and attached document) from J. H. Taylor,
Babcock & Wilcox, to R. J. Mattson, NRC, Subject: Conclusions and Detailed Analysis of the Michelson Report,
dated May 7, 1979.
74
14. at A 5-6.
75
Letter from R. J. Mattson, NRC, to H. R. Myers, Subcommittee on Energy and the Environment, Committee on
I nterior & Insular Affairs, United States House ofRepresentatives; Subject: Key Conclusions of the NRC
Staff Evaluation of the Michelson Report, dated May 24,
1979.
76Ad. at 5.
77
Michelson dep. at 44.
78
Jones dep. at 50.
79
C. Michelson, "Decay Heat Removal During a Very
Small Break LOCA for a B&W 205-Fuel-Assembly PWR,"
Tennessee Valley Authority, at 4.5, dated January 1978.
80
Derivan dep. at 11, 13-14.
81
1d. at 13-14, 29.
821d. at 18, 30.
83
Davis Besse Nuclear Power Station, "Unit No. 1Emergency Procedure EP 1202.06: Loss of Reactor
Coolant and Reactor Coolant Pressure."84
Derivan dep. at 41.
65

98'"31d at 15-16.

Memorandum from D. F. Ross, NRC, to K. V. Seyfrit,"Davis Besse 1 Abnormal Occurrence (9/24/77),"
October 20,1977.
115/d. at 1.
116
Seyfrit dep. at 15.
117
Memorandum from R. J. McDermott, NRC, to D. J.
Skovholt, "Reactor Coolant System Depressurization
Event at Davis-Besse-2 (DB-2)," October 6,1977.
116
Memorandum from R. J. McDermott, NRC, to D. J.
Skovholt, "Reactor Coolant System Depressurization
Event at Davis-Besse-2," October 20,1977.
119
210th Advisory Committee on Reactor Safeguards
Transcripts (October 7,1977) at 344.
114

120

1d. at 347-348.
1d.
at 350.
122
Seyfritdep. at 34-35.
123
210th Advisory Committee on Reactor Safeguards
Transcripts (October 7,1977) at 249-350.
121

124

211th Advisory Committee on Reactor Safeguards
Transcripts (November 3, 1977) at 174-184.
125
Faist dep. at 8.
126
Kelly dep. at 11-12, 24.

1d. at 31.

127

d. at 36.
1d. at 18, 19, 28.
88
Murray dep. at 9, 11.
89
Derivan dep. at 21.
90
1d. at 24.
91
Knop dep. at 5-7.
92Id. at 14.
93
Harpster dep. at 7.
94Id at 8-33.
95
1d. at 26-30.
86

1d. at 10.

Letter from J. G. Keppler, NRC, to J. S. Grant,
Toledo Edison Co., Subject: Immediate Action Letter Following Davis-Besse Incident of September 24, 1977,
dated September 30, 1979.
98/d. at 1-2.
99
Keppler dep. at 12-13.
100
Tambling dep. at 17.
101
1d. at 44, 46.
102/. at 38-39.
103
1d. at 39.
104
Toledo Edison Corporation, "Licensee Event Report:
NP-32-77-16," Docket 50-346, October 1977.
105
Toledo Edison Corporation, "Licensee Event Report:
NP-32-77-16 Supplement," Docket 50-346, November
1977.
106
T. N. Tambling and T. L. Harpster, "Inspection
Report No. 50-346/77-32: Davis-Besse Nuclear Power
Station, Unit 1," Docket 50-346, November 1977.
107
Engle dep. at 13-16,18.
108
1d. at 65-66.
'Mid. at 24, 28, 44.
'"Old. at 18, 28, 35-39.
"G.
Mazetis,"Trip
Report:DB-1
AbnormalOccurrence," dated September 1977.
112
Mazetis dep. at 13.
97

128

87

Id. at 14-15.

1d. at 20-22.
Dunn dep. at 23-24.
130
Kelly dep. at 29-30, 33.
131
Faist dep. at 10-11.
132
1d. at 21.
133
ld. at 24-26.
134
Babcock & Wilcox, "Toledo Edison Company Site
Problem Report-SFRCS Trip/Reactor Trip/Coolant
Spill," SPR No. 372 (November 1977).
129

17 8

Faist dep. at 22, 29.
14. at 31-33.
137
Murray dep. at 7-21.
' 381d. at 22.
1 39
1d. at 21.
140
Id. at 24.
1411.
at 32-34.
142
Derivan dep. at 44.
43' /d. at 47.
144
14. at 47.
145
at 44, 49.
146" Cognitive Dissonance and the Accident at Three
Mile147
Island," p. 1, The Energy Daily, October 11, 1979.
Kelly dep. at 29.
148
Dunn dep. at 23-25.
149
Kelly dep. at 30.
150
Memorandum from J. J. Kelly, Babcock & Wilcox, toB. A. Karrasch, E. W. Swanson, R. J. Finnin, B. M. Dunn,
D. W. LaBelle, N. S. Elliott, and D. F. Hallman, "Customer
Guidance on High Pressure Injection Operation,"
November 1, 1977.
151
Kelly dep. at 36-38.
152
Memorandum from J. J. Kelly, Babcock & Wilcox, toB. A. Karrasch, E. W. Swanson, R. J. Finnin, B. M. Dunn,
D. W. LaBelle, N. S. Elliott, and D. F. Hallman, "Customer
Guidance on High Pressure Injection Operation,"
November 1, 1977.

176/d.

1 35

1761d.

136

177
178

Dunn dep. at 35.
Karrasch dep. at 9-12,14-16.
1801d. at 14-17.
181
Id. at 20.
182
Id. at 20, 22.
163
Hallman dep. at 25-29.
184
Karrasch dep. at 22.
185
Hallman dep. at 25-29.
186
Karrasch dep. at 23.
1 7
S Kelly dep. at 45.
166
Hallman dep. at 30-31.
189
Kelly dep. at 43-44.
190
Dunn dep. at 34, 36.
19' Jones dep. at 52-53.
192
Memorandum from R. Muller, NRC, to C. Stahle,
Pebble Springs Nuclear Plant, "ACRS Questions RE Pebble Springs Review," dated November 7,1977.
*3 Id. at 1.
194
14. at 2-3.
179

195

/d. at 5.

19614. at 10.
197

Memorandum from S. A. Varga, NRC, to All Divisions of Systems Safety Branch Chiefs, "ACRS Questions on Pebble Springs," November 15, 1977.

153

19
BMemorandum from S. A. Varga, NRC, to Site
Analysis Branch Chiefs in Division of Site Safety andEnvironmental Analysis, "ACRS Questions on Pebble
Springs," November 17,1977.

154
155

Kelly dep. at 31.
Memorandum from F. Walters, Babcock & Wilcox,
to J. J. Kelly, "High Pressure Injection During Transient,"
November 10, 1977.
157
Walters dep. at 9-14, 22.
158
11. at 10-14.
159
Kelly dep. at 39-40.
16oDunn dep. at 29.
161
Memorandum from B. M. Dunn, Babcock & Wilcox,
to J. Taylor, "Operator Interruption of High Pressure
Injection," February 9,,1978.
156

199

Letter (and attached document) from J. L. Williams,
Portland General Electric Co., to S. A. Varga, NRC, Subject: Responses to 26 Questions Raised by the ACRS on
the Pebble Springs Application, dated November 30,
1977.
200
201

14. at cover letter.

Memorandum from S. A. Varga, NRC, to Site
Analysis Branch Chiefs in Division of Site Safety andEnvironmental Analysis, "ACRS Questions on Pebble
Spring," November 17, 1977.

162

Dunn dep. at 29-30.
Memorandum from B. M. Dunn, Babcock & Wilcox,
to J. Taylor, "Operator Interruption of High Pressure
Injection," February 9,1978, at 1.
164. at 1.
185
1d. at 1.
*6
1d. at 2.
167
Taylor dep. at 16-17.
168
Walters dep. at 17-18.
169
Memorandum from B. M. Dunn, Babcock & Wilcox,
to J. Taylor, "Operator Interruption of High Pressure
I njection," February 15, 1978.
163

202

Letter (and attached document) from J. L. Williams,
Portland General Electric Co., to S. A. Varga, NRC, Subject: Responses to 26 Questions Raised by the ACRS on
the Pebble Springs Application, dated November 30,
1977.
203

Dunn dep. at 54-55.
1d.
at 56.
205
Newberry dep. at 4-7.
204

206

Letter (and attached document) from J. L. Williams,
Portland General Electric Co., to S. A. Varga, NRC, Subject: Responses to 26 Questions Raised by the ACRS on
the Pebble Springs Application, dated November 30,
1977, at 24.
207
1d. at 51-52.
208
Novak dep. at 48-52.
209
NRC Meeting of the Advisory Committee on Reactor Safeguards (January 6,1978) at 201, 236.
210
1d. at 246-247.

170

171

Kelly dep. at 42-43.
Dunn dep. at 34, 36.
173
Walters dep. at 23-24.
174
Memorandum from 0. F. Hallman, Babcock & Wilcox, to B. A. Karrasch, "Operator Interruption of High
Pressure Injection (HPI)," August 3, 1978.
172

17 9

211

Israel dep. at 5.
Newberry dep. at

212
213

of Subject Facility with Dual Level Control Steam Generator, dated December 11, 1978.

11-12.

235

Memorandum from J. S. Creswell, NRC, to J. F.
Streeter, NRC, "Information for Management Meeting at
Davis-Besse," August 14, 1978.
236
R. W. Winks, Babcock & Wilcox, "Dynamic Performance of the Pressurizer During Reactor Trips at DavisBesse 1," August 31, 1978.
237
NRC Inspection Report of inspection conducted by
J. S. Creswell of Davis-Besse Nuclear Plant, Unit 1,
October 25, 1978.
238
Creswell dep. at 24-25.
239
NRC Inspection Report of inspection conducted by
J. F. Streeter, J. S. Creswell, and J. D. Smith, of Davis
Besse Nuclear Power Station, Unit 1, February 7,1979.

Taylor dep. at 31-35.
Ebersole dep. at 31.
215
Letter (and attached excerpts from minutes of the213th ACRS Meeting, January 5-7, 1978) from S.
Lawroski, NRC, to J. M. Henry, NRC, Subject: Report on
Pebble Springs Nuclear Plant, Units 1 and 2, dated January 12, 1978.
216
1d. at 19.
217
Filing of NRC Staff's Responses to Board Questions
During the Pebble Springs Pre-Hearing, Conference Heldon April 12, 1978, Before the Atomic Safety Licensing
Board, at 7, dated May 25, 1978.
218
1d. at 7.
219
Letter from L. Roe, TECO, to R. Reid, NRC, Subject:
Forwards Analysis Supporting Continued Operation of
Subject Facility with Dual Level Control Steam Generators, dated December 11, 1978.
22O
NRC Inspection Report of inspection conducted byT. N. Tamblin at Davis Besse Nuclear Power Station, Unit
1, December
16, 1977.
221
Memorandum from C. W. Tally, Babcock & Wilcox,
to M. E. McAlpine, TECO Site Operations, "Analysis of
Natural Circulation Transient Data," December 21,1977, at
1-3.
222
Meeting summary from L. Engle, NRC, to TECO,
Davis Besse Nuclear Power Station Unit No. 1 (DB-1)," Summary of Meeting on Natural Circulation Tests,"
February 14, 1978, at 1-2.
223
Letter from R. S. Boyd, Office of Nuclear Reactor
Regulation, to L. E. Roe, TECO, Subject: Natural Circulation Test-Davis Besse, Unit No. 1, dated November 29,
1977.
224
Creswell dep. at 14-16.
225
1d. at 18-19.
226
NRC Inspection Report of inspection conducted by
J. S. Creswell at Davis Besse Nuclear Power Station,
Unit 1, April 20, 1978.
227
Creswell dep. at 18-19.
228
Letter from R. J. Baker, Babcock & Wilcox, to J. G.
Evans, Davis Besse Nuclear Power Station, Subject:
Recommendations for Avoiding Pressurizer Off-ScaleI ndications, dated November 22, 1976.
229
Memorandum from C. R. Domeck, Davis Besse
Nuclear Power Station, to E. C. Novak, Davis Besse
Nuclear Power Station, "Davis-Besse Nuclear Power Station, Unit No. 1, Summary of a November 29, 1977
Incident," December 16, 1977.
230
Memorandum from C. W. Tally, Babcock & Wilcox,
to R. P. Williamson, Babcock & Wilcox, "SPR 396,"
February 10, 1978.
231
Memorandum from T. Murray, TECO, to T. Tambling, NRC, November 28, 1978.
214

240
Creswell dep. at
241

95.
Creswell
dep.
at
97.
242
NRC Inspection Report of inspection conducted by
J. S. Creswell of Davis-Besse Nuclear Plant, Unit 1,
October 25,1978.
2°Summary of telephone conversation between J.
Streeter, NRC, and T. Murray, TECO, Subject: Operationof High-Pressure Injection During September 24, 1977
Event," at 1, September 13, 1978.
244
Miller dep. at 19.
245
Summary of telephone conversation between J.
Streeter, NRC, and T. Murray, TECO, Subject: Operatic,,of High-Pressure Injection During September 24, 1977
Event," September 13, 1978, at 2.
246
Davis Besse Nuclear Power Station, Unit 1, Temporary
Modification Request, dated November 26,1978.
247
1d. at 1.
248
NRC Inspection Report of inspection conducted by
J. F. Streeter, J. S. Creswell, and J. D. Smith, of Davis
Besse Nuclear Power Station, Unit 1, February 7,1979.
249
Streeter dep. at 15-16.
250"Davis-Besse Nuclear Power Station, Unit No. 1,
Emergency Procedure EP1202.06, Loss of Reactor
Coolant
and Reactor Coolant Pressure," at 4.
251
Creswell
dep. at 26.
252
Streeter dep. at 29, 35, 38.
253
Memorandum from J. S. Creswell, NRC, to G.
Fiorelli, NRC, "Concern Regarding Voiding of Pressurizer
at Davis-Besse 1," December 19, 1978.
254
1d. at 1.
255
Memorandum from J. S. Creswell, NRC, to J. F.
Streeter, NRC, "Technical Evaluations, Davis-Besse 1,"
December 19,1978.
256
Memorandum from J. F. Streeter, NRC to J. S.
Creswell, NRC, "Technical Evaluation, Davis-Besse 1,"
December
20,1978.
257
Memorandum from J. S. Creswell, NRC, to J. F.
Streeter, NRC, "Technical Evaluations, at Davis-Besse 1",
January 29,1978.
258
Creswell dep. at 31-32, 59.
259
Streeter dep. at 52.
260
Letter from L. Roe, TECO, to R. Reid, NRC, Subject: Forwards Analysis Supporting Continued Operationof Subject Facility with Dual Level Control Steam Generators dated December 11, 1978.
261
Letter from L. Roe, TECO, to R. Reid, NRC, Subject:
Additional Safety Evaluation of Transient Resulting from

232

Letter from T. D. Murray, TECO, to J. G. Keppler,
NRC, Subject: Reportable Occurrence 78-115 DavisBesse Nuclear Power Station, Unit 1, Date of Occurrence:
November 27,1978, dated December 8, 1978.
233
Memorandum from Cartin, Babcock & Wilcox, toB.A. Karrasch, Babcock & Wilcox.
23.1

Letter from L. Roe, TECO, to R. Reid, NRC, Subject: Forwards Analysis Supporting Continued Operation
18 0

Foster dep. at 49-50.
NRC Inspection Report of inspection conducted by
J. E. Foster and J. E. Kohler, at the Davis Besse Nuclear
Power Station, Unit 1, April 25, 1979, at 10-12.

Inability of Operator to Control Steam Generator Level of
35 Inches," dated December 22,1978.

292
293

262

1d. at 9.
1d. at 9.
264
Streeter dep. at 32-33.
265
Creswell dep. at 62-64,175-176.
266
NRC Inspection Report of inspection conducted by
J. F. Streeter, J. S. Creswell, and J. D. Smith, of Davis
Besse Nuclear Power Station, Unit 1, February 7, 1979.
267
Weiss dep. at 9-12, 25, 37.
268
Memorandum from J. S. Creswell, NRC, to J. F.
Streeter, NRC, "Conveying New Information to Licensing
Boards-Davis-Besse Units 2 & 3 and Midland Units 1 &2," January 8, 1979.
269/.
at 2.
270
Creswell dep. at 178-179.
271
Memorandum from N. C. Moseley, NRC, to D.
Thompson, NRC, "Notification of Licensing Boards (AITS
F30468H2)," February 28,1979, at 1.
272
1d. at 1.
273
NRC Board Notification, March 29,1979.
274
Memorandum from J. G. Keppler, NRC, to N. C.
Moseley and H. D. Thornburg, NRC, "Recommendation for
Notification of Licensing Boards and Requests for Technical Assistance (AITS F30468H2)," January 19,1979.
275
Memorandum from N. C. Moseley, NRC, to D.
Thompson, NRC, "Notification of Licensing Boards (AITS
F30468H2)," February 28, 1979.
276
Memorandum from D. Thompson, NRC, to D. B.
Vassallo, NRR, "Information for Board NotificationDavis-Besse Units 2 & 3 and Midland Units 1 & 2," March
1, 1979.
277
Memorandum from D. B. Vassallo, NRR, to E. S.
Notification-Reactor
Christenbury,
OELD,"BoardInspector Concerns Regarding B&W Plants (BN-79-10),"
March 6, 1979.
278 Note from J. F. Scinto, NRC, to E. S. Christenbury,
OELD, Subject: Processing of Board Notices, dated April
5,1979,at 1-2.
279
NRC Board Notification, March 29,1979.
280
Memorandum from N. C. Moseley, NRC, to D.
Thompson, NRC, "Notification of Licensing Boards,"
March 28,1979.
263

294
295

1d.

Foster dep. at 22-23.
Memorandum from J. S. Creswell, NRC, to G.
Fiorelli, NRC, "Concern Regarding Voiding of Pressurizer
at Davis-Besse 1, December 19, 1978, at 23-24.
297
Kohler dep. at 60-62.
298
Bradford Interview Transcript at 128 (Pres. Com.).
299
Ahearne Interview Transcript at 48 (Pres. Com.).
300
Memorandum from J. S. Creswell, NRC, to J. F.
Ahearne, NRC, "Summary of Concerns," undated, at 1,
4-5.
301/d. at 1, 6.
302
Id. at 1, 10-11.
303
Creswell dep. at 184.
304
Ahearne Interview Transcript at 49 (Pres. Com.).
305
Bradford Interview Transcript at 131-133 (Pres.
Com.).
306
Memorandum from J. F. Ahearne, NRC, to H. Denton, NRR, and J. Davis, IE, "Status Report on Davis-Besse
Unit No. 1," March 29,1979.
307
Bradford Interview Transcript at 130 (Pres. Com.).
3 8
D Ahearne Interview Transcript at 52 (Pres. Com.).
309
Bradford Interview Transcript at 130 (Pres. Com.).
310
Keppler dep. at 26-29.
3
nCreswell dep. at 188.
296

312

Keppler dep. at 26-27.
Creswell dep. at 201-205.
314
NRC Inspection Report of inspection conducted by
R. C. Knop and T. N. Tambling at Davis Besse Nuclear
Power Station Unit 1, September 21,1978.
315
Letter from T. M. Novak, NRC, to RSB Members,
Subject: Loop Seals in Pressurizer Surge Line, dated
January 10, 1978.
316/d. at 1.
313

3171d.

319
Id.
320

at 10.

4.

dep.at1d.
Newberry dep. at 17-22.
322
Letter from J. T. Janis, B&W, to R. J. Rodriguez,
Sacramento Municipal Utility District, Subject: Rancho
Seco Nuclear Generating Station-Unit No. 1, Evaluationof NSS Cooldown Transient, dated March 23, 1979, at 1.
323
Memorandum from D. Eisenhut, NRC, to V. Stello,Jr., "Rancho Seco Nuclear Generating StationEvaluation of the NSS Cooldown Transient," March 30,
1978.
324 Letter from J. J. Mattimoe, Sacramento Municipal
Utility District, to R. H. Engelken, NRC, Subject: Operati ng License DPR-54, Reportable Occurrence 78-1, at 3,
dated March 31, 1978.
325
Transfer of Lead Responsibility from K. V. Seyfrit,
DROI, IE, to B. K. Grimes, NRR, "Rancho Seco NonNuclear Instrumentation Power Supply and Auxiliary
Feedwater Initiation," April 25, 1978, Serial No.: IE-ROI:

281

321

Foster dep. at 15, 40.
Kohler dep. at 17, 47, 64.
284
Creswell dep. at 52-57.
285
Foster dep. at 7, 26, 29, 53.
286
Kohler dep. at 20, 33-35, 46.
287Letter from J. D. Phinney, B&W, to W. Cavanaugh,III, Arkansas Power and Light Co., Subject: Arkansas
Nuclear One-Unit One Pressurizer Level Setpoint B&W
Reference NSS-8, dated April 3,1975.
288
Letter from R. J. Baker, Jr., B&W, to J. G. Evans,
Davis Besse Nuclear Power Station, Subject: Recommendations for Avoiding Pressurizer Off-Scale Indications, dated November 22, 1976.
289
Memorandum from C. W. Tally, B&W, to R. P. Williamson, B&W, "SPR 396," February 10, 1978.
280
Anderson dep. at 16-17.
291
Kohler dep. at 55-57.
282

283

78-04.
18 1

337Letter from J. G. Herbein, Metropolitan Edison

MMeeting Summary from G. B. Zweitig, NRC, "Cooldown Transient of March 20, 1978," (June 20, 1978)
dated July 13,1978, at 3.
327
Memorandum from R. Lobel, DOR to P. S. Check,"Summary of Meeting Held at Rancho Seco Nuclear
Powerplant on June 10, 1978 to Discuss a Recent Cooldown Event," at 6, July 31, 1978.
328
Telephone logbook of F. Hebdon, NRC; entries forcalls to R. Lobel, NRR, July 9, 1979.
329
1d., entries for calls to G. Zweitig, NRC, July 10,
1979.
330
Letter from I. D. Green, B&W, to T. D. Murray, Davis
Besse, Subject: SMUD Rapid Cooldown Transient, dated
August 9, 1978, at 2.
33 Taylor dep. at58.
332
Metropolitan Edison Company, "Three Mile Island
Nuclear Station GPU Startup Problem Report," Docket
50-320, March 30,1978.
333
1d. at 2.
334 Burns and Roe, Inc., TMI Unit No. 2, Engineering
Change Memo, dated April 6,1978.
336
1d. at 1.
338
TMI Nuclear Station-Unit ##2, Burns and Roe
Nuclear Safety Review, dated April 14, 1978.

Company, to B. H. Grier, Subject: Special Report Concerning the TMI-2 ECCS Actuation of March 29, 1978,
dated June 27,1978.
"Memorandum from D. M. Sternberg, NRC, to K. V.
Seyfrit, "Three Mile Island-Pressurizer Relief Valve Control System (AITS #F14674H2)," March 31,1978.
3391d.
34°

Stemberg dep. at 6.
1d. at 19.
342
14. at 40-44.
343 Memorandum from K. V. Seyfrit, NRC, to E. J.
Brunner, "Three Mile Island Unit No. 2/Pressurizer Relief
Valve (AITS F14674H2)," May 3,1978.
341

3"Id.

345 Final Safety Analysis Report (FSAR), Three Mile
Island- Unit 2, Vol. 6, Sec. 7.4.1.1.6.
34

sWoodruff dep. at

347
348

1 82

Sternberg dep. at
Seyfrit dep. at

8.

48.

42-43.

D PRESSURIZER DESIGNAND PERFORMANCE:A CASE STUDY
The pressurizer is a steel cylinder with hemispheres welded on either end. It is attached to thereactor coolant system by a pipe, as shown in Figure I-11. The purposes of the pressurizer are to
maintain system pressure and to absorb system
volume changes during transients. Heaters near thebottom of the pressurizer heat the water so that asteam bubble Is maintained in the top of the vessel.
This bubble serves as a cushion. The cushion canbe enlarged by additional heating, to force water outof the pressurizer and back into the reactor coolant
system, thus increasing system pressure. By cooling the pressurizer steam, the bubble is shrunk, andsystem pressure is decreased. Figure 1-12 illustrates
the pressurizer.
The pressurizer also has a water level indicatorthat shows the level of the boundary between thewater and the bubble. Operators commonly use thepressurizer water level indicator to tell them aboutwater level in the entire primary system. Under normal circumstances, if there is some level indicationi n the pressurizer, the rest of the system should be
full of coolant; if the pressurizer level disappears(goes below zero), there may be no way to determine how much water is in the system or even
whether the reactor core is covered with coolant
water.

I n reading the information that follows, the reader
should keep in mind that pressurizer level indication
can tell the operator something about (1) pressure in
the reactor coolant system; (2) reactor coolant
i nventory (how much water is in the system); and(3), in some instances, whether boiling is taking
place in the reactor. A basic design concept of apressurized water reactor is that sufficiently highpressure is maintained in the primary system so thatboiling does not take place in the reactor during
reactor trips.' During loss-of-coolant accidents,
boiling may occur for some period of time. Rowever, safety systems, such as high pressure injection pumps, are designed to activate automaticallyand cool the reactor core.
Pressurizer level can respond in a number ofways during transient conditions (such as reactor
trips and accidents). During the initial phase of theTMI-2 accident, for example, it first moved upward,
then downward, and then upward again. The first
upward movement was in response to the "bottlingup" of heat in the reactor. As temperature climbed
i n the reactor, the water expanded and increased
the level in the pressurizer. The level then dropped
when the reactor scrammed, and reduced the generation of heat by over 90%, causing the reactor
coolant to shrink, and temperature and pressure to
183

184

FIGURE 1-12. The Pree:urizer

185

occur in the reactor coolant system, affecting theremoval of heat from the reactor, the operation of
the reactor coolant pumps, and eventually thefuel itself.

sharply reduce. When the operators observed thedeclining level they responded immediately by stopping the normal letdown flow of water out of thereactor and increasing the makeup flow of wateri nto the reactor. The level rose again (as the operators expected), but then something highly unusual
happened. The level did not stop rising, but continued increasing until it indicated to the operator thatthe pressurizer was completely full of water. The
operators throttled the high pressure injection( which had come on automatically) in the belief that
less, not more, water was needed in the primarysystem. Though they did not realize it, the stuckopen relief valve in the top of the pressurizer was
permitting coolant to flow through the pressurizer
and out of the system.
The main effect of the pressurizer level indication
during the Three Mile Island accident, then, was thatits increasing misled operators into thinking that thereactor coolant system was full of coolant, when infact it was not. The accident demonstrated, among
other things, the extent to which operators had
been trained to key on pressurizer level to tell themwhen to initiate various manual actions. In fact, theoperators' decision at Three Mile Island to throttle
high pressure injection showed the extent to which
they were accustomed to seeing this emergency
safety system actuate during the anticipated operational transients and that they were conditioned toturn it off when the anticipated transient appeared
to have run its course.
Much of the following discussion addressing
pressurizer level pertains to what happens during anormal reactor trip, not an accident like Three MileI sland involving a stuck-open valve. During a normal
trip, the pressurizer level moves up, then down, andthen up again, but stops going up before the pressurizer becomes full of water. The main area ofi nterest in this discussion is the downward movement in the cycle, what happens when the pressuri zer level goes low. Three concerns may be
encountered when the level drops, depending on
how far it goes:

Pressurizer level indication is therefore a serious
i ssue of importance to the operator's knowledge ofreactor coolant system conditions. According toJohn W. Anderson, Arkansas Nuclear One (ANO)
Plant Manager, "As far as the PSC [Plant Safety
Committee] is concerned, when all pressurizer leveli ndication is lost then there is no way to knowwhether the core is covered with water and therefore, a safety question exists." 2
Ed Frederick, a control room operator who was
manipulating the makeup and high pressure injection
controls in the TMI-2 control room during the initialstages of the TMI accident, testified:
Specifically on the pressurizer, you often find yourself working very hard to maintain yourself withinthose limits, even on a simple reactor trip. It willtake several manual actions to maintain, fori nstance, the minimum 100-inch figure for keeping
the heaters covered. Much of the reactor trip procedure is devoted to pressurizer level control, so I
can't really think of anywhere that we purposely
ignore this or try to exceed it and/or let it beexceeded because they are so important to theplant, pressure control....
Q: So you obviously ... are concerned with pressurizer level not going down?
A: Right .... 3

The pressurizer at TMI-2 is a standard B&W
design for 177 fuel assembly plants first developed
for Oconee 1 and 2 plants in 1967. 4 (B&W diligently
searched for the design calculations but could not
locate them.) Figure 1-13 illustrates the location ofpressurizer level instrumentation taps for various
B&W plants. The location of these taps controls therange over which the operator can monitor thewater level in the pressurizer. Figure 1-14 schematically represents the location of heater bundles forthe standard 1500-cubic foot pressurizer.
Past performance at B&W plants has revealed
problems with the maintenance of pressurizer level. 5
Some of these problems have resulted from malfunctions of the main steam safety relief valves or
turbine bypass valves during loss-of-feedwatertransients. The main steam safety relief valves on a
B&W facility are designed to open during a normal
loss-of-feedwater transient, because of a reductionof heat removal capacity on the secondary side of
the steam generator. This reduction of heat removal capacity causes elevated secondary tempera-

1. The level may go down to the point at which thepressurizer heaters cut off. This action removes
the heat source that can be used, either automati cally or manually, to compensate for pressure
decreases.
2. The level drops further to the point at which thel evel indicating instrumentation cannot show theoperator where the level of water is in the pressurizer; that is, the level reads zero.
3. The level drops further and the pressurizer empties. If pressure drops low enough, boiling may

18 6

18 7

18 8

tures and thus causes pressures that exceed thesafety relief valve setpoints. So the B&W design
results in a more frequent challenge to the valve
than other PWR designs do.
Main steam safety relief valves have a history of
malfunctions. These valves are not classified assafety related, so they are not subject to the controls of the nuclear quality assurance program.
While such valves have been used in fossil fuelplants for many years, the restrictive requirementsfor pressure control in nuclear plants tax the capability of these valves to perform satisfactorily.
One such malfunction occurred on April 23, 1978,
at Three Mile Island, Unit 2. During a reactor trip,
five main steam safety relief valves, after opening
during a loss-of-feedwater transient, failed to close
properly. As a result, the steam generators continued to steam directly to the atmosphere, removing
more heat from the primary system than was
intended. The overcooling of the reactor coolant
caused shrinkage and loss of pressure level indication; that is, the level indication went to zero.
I n a report submitted to the NRC, Met Ed statedthat the high pressure injection system (HPI) was
automatically actuated as the reactor coolant pressure dropped. 6 The report further indicated that the
HR was bypassed within 6 seconds of its actuation.
The bypassing took place while indicated pressurizer level was zero. Later in the event, high pressure injection was again initiated. A B&W study
performed on the event concluded that the pressurizer never emptied. The B&W report also stated: "Itappears that only the operator's timely initiation of
HPI prevented this from occurring ...." 7 Subsequentcalculations indicated that the core remained
covered with water during the transient. However,boiling was concluded to have occurred. 8
The following sections describe the design of thepressurizer; relate a history of correspondence andevents, including two NRC inspections, which illustrate how problems with the pressurizer were identified and addressed; summarize this history; and set
forth conclusions and recommendations.

absorb system fluid volume changes during all normal and abnormal transients."
Step 3 of the procedure (Section IIIA), which
deals with minimum pressurizer level, is as follows:
Set the pressurizer minimum level (volume) at thehigher of:a. 150 cu ft, orb. the volume in the pressurizer lower head up to
the tangent line.

The level should not drop below this point during or
after a reactor trip. 9

The volume in the pressurizer lower head is not
more than 56.8 cubic feet. 10 Therefore the minimum
level (volume) for the purpose of this calculation is
150 cubic feet. This volume corresponds approximately to a level of 30 inches above the juncture of
the lower head and the cylindrical body of the pressurizer. For an Oconee or TMI pressurizer, in which
the lower tap for the pressurizer level indicator instrumention is located 18 inches above the junctureof the lower head and cylindrical body, a minimum
indicated level of approximately 12 inches should
result during or after a reactor trip. However, thelower tap at the Arkansas Nuclear One (ANO-1)
plant is located 58 inches above the juncture. Thus,at ANO-1, at the limit of the design, the operator
would see l evel indication at zero, but the actual level would be 28 inches below the bottom tap.
To determine the maximum outsurge (flow of water out of the pressurizer during a trip or transient),
the B&W design document advises:
Obtain the maximum outsurge. The outsurge is associated with a reactor trip from full power. The
reactor coolant system temperature will drop fromthe reactor coolant system temperature at fullpower to the temperature corresponding to the turbine bypass set point ....nThis definition of maximum outsurge, which is associated with the minimum permitted pressurizer
level during a transient, assumes that the maximum
temperature change experienced from a trip at fullpower is governed by the bypass valve set point.
The assumption does not take into account possible
additional temperature changes caused by turbine
bypass valve malfunctions, secondary safety relief
valve malfunctions, or feedwater system malfunctions.
To locate the level taps, step 14 (Section IIIA) of
the B&W analysis states:

Review of the B&W Pressurizer Design

The B&W design document, "Design and Performance Analysis-Pressurizer," which details how
the pressurizer was designed and defines the conditions under which it was intended to function,states: "The pressurizer is an integral component of
the primary system. Its function is to maintain system pressure within system design values and to

Set the location of pressurizer level indication tapsby the following criteria:
a. The lower level taps must be below the minimumpressurizer level to avoid loss of indication duri ng the design outsurge.

1 89

b. The upper level taps must be above the maxi mum pressurizer level to avoid loss of indication
during the design insurge.12high). However, the pressurizer design document
does not require that an analysis of pressurizer performance be performed under stuck-open safetyvalve conditions.

The design document also requires a check of
the computed PZR (pressurizer) volume by compari ng the step 14 criteria with pressurizer level
response to certain transients as calculated by two
computer programs. Documents examined in thisi nvestigation reveal that at least one of those programs was never certified as required by B&W
design requirements; that is, validated by comparison against actual operating experience in at least
three different applications. 13
As the lower level taps for the ANO-1 seriespressurizer were located above the minimum pressurizer level as defined in procedure step 3 (Section
IIIA), as pointed out above, they were located contrary to the design requirements. A B&W engineeri ng change authorization document specificallystates that the tap location was changed to save
$18 000 in the cost of welding. 14
Similarly, there was an analysis available to B&W
i ndicating that in event of a stuck-open pressurizer
relief valve-such as'at TMI-the upper-level pressurizer taps might be covered, either in the
TMI/Oconee or the ANO-1 pressurizer. On October
16, 1973, R. Jones, B&W ECCS Engineer, obtained
the results of a CRAFT (Version 2) calculation (atype of computer analysis) performed to analyze thestuck-open safety valve transient. 15 The results ofthis analysis were provided to the NRC in a
response to question 15.11 for the PSAR for the Bellefonte application, dated November 1, 1973. The
question requested the following information: "Provide in Section 15.1.13 a discussion of the events following the opening of a pressurizer safety valve as
required in the October 1972 Standard Format andContent of Safety Analysis Reports for Nuclear
Power Plants."
The response stated in part: "[A]t 166 seconds,
the flow increases sharply as a two-phase fluid isbeing leaked through the safety valve rather thansteam." Figure Q15.11-5, titled "Inner Vessel Liquid
Volume for a Pressurizer Safety Stuck Open," wasattached to that response. This figure showed voiding in the reactor vessel occurring within 200
seconds of the safety valve failure. The volume of
fluid in the reactor vessel would indicate significant
flow of reactor coolant to the pressurizer.
Had B&W compared the results of the CRAFT
calculation to the pressurizer design requirements,
they would have noted that the upper level taps
would have been covered during the stuck-open
safety valve transient; that is, that pressurizer leveli ndication would have been at its maximum (offscale

History of Pressurizer Level Problems

On August 13, 1974, a generator breaker trip test
was performed at TMI Unit One. During this test,
pressurizer level fell to approximately 40 inches.
The pressurizer heaters cut off at 80 inches, thereby reducing pressurizer pressure. During a B&W
presentation to the customer on September 4,1979,
J. G. Herbein, Plant Superintendent, stated that
there were two areas of operation that required improvement: first, during a reactor trip the pressurizer level should not fall as low as it did, and second,
during a turbine trip from 100% power the reactor
16
should not trip.
It was further noted in the resulting Site Problem
Report that the plant might further depressurize andhigh pressure injection might be initiated. The lowpressurizer level during the transient was initially attributed to the turbine bypass valves staying open
l onger than necessary, but was later attributed to17
overfeeding with feedwater.
On August 29, 1974, R. C. Luken, Plant Integration, B&W, raised the question of the effect on pressurizer response of turbine bypass valve matfunction in a memorandum to B. A. Karrasch, Control
Analysis, B&W. (B&W diligently searched for thisreferenced memorandum but could not locate it.) Ina September 18, 1974 memorandum, Karrasch noted to Luken that, "Depending upon the conditions of
the makeup system, the pressurizer and surge line
could be emptied causing the reactor coolant system pressure to drop to hot leg saturation pressure
and possibly violate fuel compression limits." Karrasch further stated, "The current Control Analysis
workload would preclude an analysis of this type
before the first quarter of 1975." 18
Karrasch then turned his attention to pressurizes
level indication. He wrote:

Mr. Burris has recently conducted a survey of thepressurizer level tap locations for all the 177 FA
plants. The lower tap on the Toledo (Davis Besse)pressurizer is 40" above the normal tap location
and will result in loss of pressurizer level indication
during a normal reactor trip. Even though adequatelevel exists, the loss of level indication is probably
not acceptable to the customer and should be investigated before plant startup.

Karrasch then described three options to "solve
this potential problem with indicated pressurizer level." First, the plant could operate safely at a higher
operating level except possibly for ATWS (anticipat190

ed transients without scram). Second, the tap could
be lowered 40 inches. Third:l ocation of the low level tap at ANO based on Three
Mile Island, Unit 1 and Oconee I and 11.22

Change nothing and inform the customer that hewill lose indicated pressurizer level following a normal reactor trip transient (I believe this will be unacceptable to the customer). We may be able toshow that with proper use of the makeup and letdown valves, and using Oconee, TMI and Arkansas
data, that the pressurizer level will not be lost foll owing a reactor trip. This would also require
analysis and at best may show that the indicatedpressurizer level will stay just on scale for the assumed conditions. 19

Anderson forwarded the PSC concerns in amemorandum to W. Cavanaugh, Manager, Nuclear
Services, Arkansas Power and Light (AP&L), dated
October 15,1974.23
On October 18, 1974, AP&L responded to the
B&W recommendations to increase the pressurizer
l evel. Cavanaugh noted:
We have subsequently learned that, during thesame transient [Generator Trip] at TMI-1 the pressurizer level first increased by 60 inches. Applying
this 60 inch rise to the proposed maximum operati ng level of 225 inches, the level would reach 285
i nches. This is within 5 inches of a previous B&W
recommendation for an administrative reactor trip
at 290 inches and approaches loss of indicationhigh conditions.24

In a September 24, 1974 memo, E. R. Kane,
Reactor Performance Service, B&W, notified J. N.
Kaelin, the B&W Site Operations Manager at Arkansas Nuclear Unit One, of the pressurizer level problem. Kane wrote:
Evaluation of data from Oconee Units I and II and
TMI-1 reveals the possibility of an extremely large
and rapid decrease in pressurizer level during RC
pressure transient following reactor trips. TMI-1 experienced a drop t ~ 3" during the Generator Trip
Test from 100% F.P0

Cavanaugh stated that the recommendation to increase pressurizer level could not be implemented
because:
1. No analysis has been provided to AP&L to verify
that this change will not cause the pressurizer tofill solid resulting in loss of level indication during
a load rejection without a reactor trip.
2. No analysis results have been provided which
i ndicate that the accident analysis contained in
the FSAR would not be affected. Parameters
affected would include (1) additional mass
released due to increased Reactor Coolant System (RCS) volume, and (2) time for pressurizer
to fill solid.
3. Basing the recommendation on a transient including one turbine bypass valve partially stuck
open is not valid since the turbine bypass system is non-Q and more than one valve may stick
open resulting in a more severe transient.
4. Explain the reason for the difference in the location of the level tap at ANO versus TMI-1 andOconee 1, 2 and 3.25

He continued:
Because the upper and lower pressurizer level taps
at Arkansas are forty (40) inches below and above,
respectively, the upper and lower taps at TMI-1, thepossibility exists that level indication will be lostcompletely following a significant RC pressure transient. For this reason, it is recommended that thepressurizer level control setpoint be increased by
30" to 210" with an operating band of ±15 inches.
Since pressurizers at other B&W plants have leveltaps locations identical to Arkansas, the performance of the plant during a reactor trip from 40%
FP is vitally important for evaluating proposedcorrections to this problem. Please forward pertinent reactimeter data (particularly, pressurizer level and RO pressure) to Lynchburg as soon as possible after the trip.20

In the meantime, correspondence between B&W
and AP&L was going back and forth about acceptance criteria for the pressurizer level in reactor trip
tests.
Kaelin, B&W, wrote AP&L's Anderson amemorandum on October 29, 1974, about changing
these acceptance criteria on pressurizer level. He
said a recent reactor trip test had resulted in failure
to meet these criteria. Kaelin stated that the pressurizer heaters would cut off during reactor trips because the pressurizer was not designed to keepthem covered. He also noted that the location of
the level taps ensured a sufficient volume of reactor
coolant in the pressurizer at 0 inches indicated andthat a steam bubble still existed when the level was
320 inches indicated. He continued, "The acceptance criteria [in the test] ... should be revised toapply only to normal pressurizer system operation

In a September 26, 1974 memorandum to J.
Anderson, ANO Plant Manager, Kaelin recommended increasing operating level in the pressurizer21
and notified him that the pressurizer level taps were
40 inches higher and lower than at TMI andOconee.
On October 2, 1974, G. H. Miller, Chairman of the
ANO Plant Safety Committee (PSC) forwarded theminutes of a committee meeting that took place on
October 2, 1974 to J. Anderson. The minutes state:
The PSC feels this (increasing level to 210 inches)i s an unreviewed safety question since no analysis
appears to have been conducted to verify [that] thepressurizer will not go solid during a load rejection
without reactor trip, thus also causing a potential
l oss of pressurizer level indication. The PSC
recommends that B&W be requested to justify the191remains in the pressurizer and that the reactor(prior to reactor trip) and another acceptance cri-

teria of 0 to 320 inches indicated, be establishedfor26
the transient associated with a reactor trip."
On November 1, 1974, R. F. Rogers, a Reactor Inspector assigned to Region II, filed the following report after reviewing a turbine-reactor trip test per-core is not uncovered.

ProI n the next inspection report, NRC's ANO-1 Pro-j ect Inspector, M. L. Kidd, resolved the unresolved
i ssue reported by Rogers. He wrote:

The documentation regarding inability to meet cercriteriainTP
800.14,tain
acceptance" Turbine/Reactor Trip Test," at forty percent power
did not fully justify acceptance of the results. (ROReport No. 50-313/74-14, Details II, paragraph 2.a).
On November 11, 1974, further explanation as towhy the test results were acceptable was enteredinto the test summary. This additional justification
was reviewed and accepted by the Test Working
Group on November 20,1974.
Regarding Criterion 8.1.01.002 which requiredthat high pressure injection (HPI) not be initiated, it
was explained that this referred to automatic initiation of HPI due to low reactor coolant system pressure. The fact that HM was manually initiated(starting of a makeup pump) due to low pressurizer
29
l evel did not detract from the test results .

formed at ANO-1:

Two acceptance criteria were not satisfied in theperformance of this test. Paragraph 8.1.01/002 requires that high pressure injection not be initiatedand Paragraph 8.2.01/003 requires that pressurizer
level remain between 40 inches and 300 inches.
High pressure injection was manually initiated due
to decreasing pressurizer level while the actual level reached approximately 31 inches. The corrective
action listed in the test document for these deficiencies indicate that none is possible and thatthese deficiencies are characteristic of the primarysystem. ( Emphasis added.)This test was approved for final acceptance by

the station superintendent on Form A-16, Test Endorsement Record, on October 4, 1974. This form
states that all deficiencies and discrepancies havebeen cleared and all acceptance criteria have beenmet.

I n discussions with licensee [ANO] representatives,
the inspector was shown a letter from Babcock andWilcox, dated October 29, 1974, which provided
technical justification for a lower pressurizer levelli mit and recommended that the licensee revise its
acceptance criteria as presently stated in this test.
This had not been done. Inability to meet test acceptance critera in the power ascension test program must be fully documented and evaluated prior
to final acceptance by the plant superintendent.
This evaluation and acceptance must be completed
for this test and will remain an unresolved item. 27

On November 18,1974, a reply from Baker (B&W)
answered the October 18, 1974 letter from Cavanaugh (AP&L), in which Cavanaugh had rejected
B&W's recommendation to solve the pressurizer
l evel problem by increasing the normal operating
l evel from 180 inches to 210 inches. That suggestion was now withdrawn and Karrasch's third
alternative-"do nothing"-was adopted with an additional suggestion for quick operator response in
the event of a reactor trip. Baker stated:

The B&W recommendation to increase the normal
operating pressurizer level from 180 inches to 210
i nches was intended to be a temporary measure topreclude possible loss of indicated pressurizer level
following a reactor trip. Operating data from
Oconee and TMI shows that the pressurizer level
may approach a zero indication at Arkansas followi ng a reactor trip, depending upon initial conditionsof the pressurizer, the primary makeup and purification system response and the steam relief system response. Based upon a TMI concern that
their indicated level might be lost for various conditions following a reactor trip, we assumed Arkansas
would have the same concern and recommended
the level setpoint increase to minimize the probabili ty of this occurrence. After plant startup testing
and with data in hand from several reactor trips, therecommendation would then have been reevaluated. Further evaluation of the increased level setpoint has resulted in a revised B&W position, andwe now feel that the original 180 inch pressurizer
level setpoint should be retained and the previous
recommendation be disregarded. Actual reactor
trip transients at Arkansas will still enable us toevaluate the pressurizer level response and even if
indicated level is lost momentarily, the actual level
will still be available to maintain RC pressure, whichis the parameter of interest. We would suggestthat the operators be instructed to secure letdown
flow and increase makeup flow immediately follow-

The ANO Test Working Group that reviewed
startup test results, met on November 20, 1974. 28
They reviewed the test deficiencies observed during
the turbine reactor trip test. They resolved these
deficiencies using the following rationale:

1. Regarding the acceptance criterion that highpressure injection not being initiated, they concluded that since it was actuated manually in-stead of automatically, the acceptance criterion
was met.
2. They stated that reactor coolant temperatures
were lower than designed because of equipment
malfunctions.
3. Regarding the acceptance criterion that pressuri zer level not go below 40 inches during the test,

they noted that the ANO pressurizer lower leveltaps were 40 inches above other comparable
B&W plants, and further, that the only limit onpressurizer level should be that it remain onscale(greater than 0 inches) to assure that water192

i ng a reactor trip to help maintain the ;iressurizer
level; these actions are being taken at Oconee and
TMI. 30

During December 1974, pressurizer level indication was lost during a trip from 100% power. 31
On December 6, 1974, Cavanaugh replied to G.
M. Olds, Senior Project Manager, B&W:

[ You] withdrew your recommendation to increase
the normal operating level from 180 inches to 210
i nches indicated level to preclude possible loss ofi ndicated pressurizer level following a reactor trip.
However, that letter did not address the fact thatANO-1 lower level tap is 40 i nches
32 above the tap
on Oconee and Three Mile Island.

Cavanaugh then pointed out that the FSAR showed
an erroneous location for the level tap and that areactor trip from 75% full power (FP) resulted in lossof indication for 45 seconds. He further explainedthat following trips from 100% FP, the level indication
could be lost in excess of 1 minute.
On December 11, 1974, D. A. Reuter, Licensing
Engineer, AP&L, wrote Cavanaugh about future test
requirements:
I can also find no unreviewed safety question involved in reducing the acceptance limit on the pressurizer level, but did have some questions on thepressurizer level instrumentation as noted in reference 5 [memo, Cavanaugh to Olds, December 6,1974]. These questions do not, however, directly
affect the acceptance criteria on lower limits andthus I concur with this change.33

range. Cavanaugh has said that his FSAR also indicates 0-400 inches as opposed to 320 inches. 37
On January 22, 1975, Cavanaugh wrote Anderson:

On the matter of changing the acceptance criteria
on reactor trip to [greater than] 0 [inches] level indication on the pressurizer [versus greater than] 40[inches), B&W said that this change was due to thedifference in lower level tap location between
Oconee and ANO-1. B&W further stated that theacceptance criteria could be that the HPSI actuation setpoint on the RCS pressure is not reached.
Thus, if we lost level indication during a test, we
could justify the results as acceptable based on the
RCS pressure during the transient. 3B

On February 3, 1975, G. Miller (AP&L) forwarded
to Anderson the minutes of a PSC meeting that took
place on January 28, 1975. The minutes noted that:"Committee reviewed letter NDC 2183 [memo, Cavanaugh to Anderson, January 22, 1975], Pressurizer Level Setpoint and did not concur with loss of indication statement. Committee views this as an un39
reviewed safety question."
On February 6, 1975, Anderson responded to
Cavanaugh's January 22 memorandum as follows:

Below are comments on above named subject, as
listed by the Plant Safety Committee. I concur with
P.S.C.
Paragraph 1 [memo, Cavanaugh to Anderson,
January 22, 1975] states that we have no problems
on loss of level indication in the pressurizer as we
still have RCS pressure indication. The PSC does
not agree because we have never been shown thatjust staying above the HPSI [HR] setpoint (1500
psig) ensures that the Rx [Reactor] core is covered
with water. As far as the PSC is concerned, when
all pressurizer level indication is lost then there is
no way to know whether the core is covered withwater and therefore, a safety question existswhich 2s
unreviewed and probably not easily
2
solvedOn December 12, 1974, a telephone conversation
was held among Baker, Cavanaugh, and Reuter.
B&W had no documentation regarding this telephone conversation.
Statements by W.
Cavanaugh, 34 J. Anderson, 35 and D. Reuter 36 i ndicate
either that the reason for the tap change cannot berecalled or that a satisfactory explanation for the tapchange was not received.
I n response to a Special Inquiry Group (SIG) request, B&W furnished the file copy of the December
6, 1974 memorandum from Cavanaugh to Olds.
This memorandum includes a handwritten note associated with the initials R.P.W. (Assumed to be
those of R.P. Williamson, since he was on the distribution list). The note states, regarding item 1 (FSAR
Figure 4-6): "This is probably generic on 177 F.A.
( Fuel Assembly) Plants ... NSS 8-14." NSS 8-14
refers to the contract numbers for ANO, Oconee 3,
Rancho Seco, Midland 1 and 2, and Davis Besse 1.
I n addition, we reviewed the FSAR copy maintainedby the NRC Licensing Project Manager, G. Vissing,for data pertinent to pressurizer level instrumentation. Table 7-11 in the FSAR lists the range of thepressurizer level instrumentation as 0 to 400 inches.
This information is contrary to the actual 320-inch

On March 3, 1975, a memo from Cavanaugh toGovers, Service Project Engineer, B&W, addressed
this concern about voiding in the reactor coolant
system. The memo refers to the December 12,1974
telephone conversation by stating:[I]t was pointed out by B&W that there is no operational problem as long as the pressure is staying
away from the automatic HPSI actuation setpoints;
that manual HPSI [HPI] initiation is not required aslong as a RCS pressure indication is available in thecontrol room; and that the pressurizer is sized tomaintain RCS pressure even if the level indication islost. B&W further stated that the acceptance criteria on pressure following a reactor trip could bethat the HPSI [HPI] actuation setpoint is notreached. In order for us to evaluate the above information, we request that you provide us with information showing that staying above the HPSI[HPI] setpoint (1500 psig) ensures that the reactor

193

dication in the pressurizer following a reactor trip.
From that letter, it can be seen that as long as water remains in the pressurizer the core will remaincovered and the HPSI [HPI] setpoint will not bereached. If the pressurizer empties, HPSI [HPI] will
be automatically initiated due to the rapid pressure
drop mentioned in their letter. 43

core remains covered with water. This is necessary in completing our review of the deletion ofmanual HPSI initiation from the procedures followthe number
ing reactor trip which has an impact on 40
of HPSI [HPI] transients during plant life.

I n the meantime, AP&L's Safety Review Committee (SRC) had also reviewed the pressurizer levelsetpoint and concluded that it was not an unresolved safety question-the opposite of the PSC's
conclusion. On March 3, 1975, the Safety Review
Committee met to consider this difference of views.
The committee's minutes record:

On April 30, 1975, after the PSC had reviewed
the April 15, 1975 memo, Anderson replied to Cavanaugh:

It is agreed that staying above the 1500 psig setpoint ensures that the Rx core is covered with water. However, since the pressure should stay
above 1500 psi until the pressurizes is emptied
and then immediately drop to well below the 1500
psig setpoint, it is too late for proper corrective action since the steam bubble would then be drawn
i nto the Reactor Vessel. Once level indication is
lost, there is no way for the operator to know
where the Pressurizer level is until an immediate
drop in pressure indicates that the pressurizer is
dry or until its level increases (due to HP injection
and Twe leveling out) to the point of being on scale
again.
There is an alternative, which the PSC has
recommended that Operations use in the event of a
Reactor Trip. (Actually this technique has been required on all Rx trips to date.) This is to initiate
High Pressure Injection manually as soon as possible following confirmation of a Reactor Trip. This
technique can ensure that Pressurizer level will not
drop below its indication range provided HPI is initiated early enough following the trip. There is aproblem with this, however, in that according to
B&W the HPI nozzles at the point of entry to the
RCS have a design life of only 40 cycles (temperature transient). Although this number does not appear in the FSAR, AEC Question 4.1 shows an all owable 480 transients for the HPI System. Even at
480 cycles this is only 12 trips per year for 40
years and experience indicates that we will probably have more than 12 trips in an average year.
I request that the SRC review the PSC's recommendation to manually initiate HPI upon confirmation of Reactor trip and that Nuclear Service personnel communicate with B&W to determine if 40
cycles is, in fact, the design life for the HPI nozzles.
Please forward your recommendations as early as
possible. 44

FollowJanuary minutes. The PSC reviewed letter NDC
2183 [memo, Cavanaugh to Anderson, January 22,1975], Pressurizer Level Setpoint, and determined it
to constitute an unreviewed safety question. The
SRC had previously reviewed this letter and foundit to not constitute an unreviewed safety question.
Since there had been little communication between
any PSC members and SRC members on thismatter, there was some confusion about it. Morei nformation will be gathered and presented at thenext SRC meeting.41

The SIG reviewed the subsequent SRC meeting
minutes for March 7, 1975. There was no mentionof pressurizer level indication. The SRC meeting
minutes for March 17, 1975, do record that the SRC
reviewed the March 3, 1975, PSC minutes, but noreference i s made to the disposition of the PSC'sconcern about pressurizer level indication. On April3, 1975, B&W responded to AP&L's request for ananalysis in a memo from J.D. Phinney, Manager,
Operating Plant Services and Maintenance, to Cavanaugh. It stated:

Even though the pressurizer water outsurge duringsystem cooldown will allow system pressure to fall
below 2155 psig, data from reactor trips at B&W's
operating plants shows that the RC pressure
remains well above 1500 psig. With the RC cooldown established by means of the turbine bypass
valves' pressure setpoint, RC pressure will not drop
to 1500 psig unless the pressurizer is completely
drained. If the pressurizer were to drain completely, RC pressure would drop rapidly to the saturationpressure for the hottest water remaining in the RC
system. The temperature of this water would be
between 550F and 579F with a resulting RC pressure of 1010 psig to 1300 psig. This resulting pressure band if the pressurizer were to empty followi ng a reactor trip is well below the 1500 psig HPSI
automatic initiation setpoint. Thus 1500 psig is anadequate low pressure setpoint for ensuring thatthe reactor core remains covered with water.42

I n May 1975, pressurizer level indication was lost
following a reactor trip from 100% power.

Phinney (B&W) visited the ANO site during May

Anderson, the Plant Manager. He recorded that:

Loss of pressurizer level indication on unit trip,
although may be technically justifiable, certainly is
not desirable. The 40 cycle limitation on HP injection on top of this further complicates the problem.
AP&L is currently deciding if this condition is a significant design deficiency, reportable to the NRC. I[ Phinney] indicated to Mr. Anderson that B&W has
stated our position and that additional work on our

On April 15, Cavanaugh (AP&L) informed Anderson (AP&L):41

Attached is reference 3 [letter, Govers to Cavanaugh, March 3, 1975], from B&W which provides
their answers to PSC comments on loss of level in194

part would be considered enhancement and wewould consider such additional work under the
Master Services Contract. There are some things
which can be done such as analysis to increase thenumber of allowable HP Inj. [injection] cycles orchanging level taps and instrumentation. I [Phinney]understand there is a pressure tap on the surgeline. 45

whenever RC pressure decreases below 1800 psig
or pressurizer level approaches a zero indication.
Winks commented that starting a second makeup
pump would have a small impact on pressurizer level. He also recommended setting the pressurizer
level setpoint at 190 to 195 inches.
In response to AP&L's second request Winks
wrote:On June 10, 1975, Cavanaugh (AP&L) contacted
D. J. Stokes, Bechtel Project Manager, to request
an analysis for actuating the standby makeup pump
to automatically supply additional flow to preventl ow pressurizer level.
On July 9, 1975, E. H. Smith, Bechtel Project Engineer, responded to Cavanaugh's request. He stated that the requested analysis showed that simply
starting a second pump would probably not provide
sufficient flow to keep pressurizer level on scale.
By adding a valve, sufficient flow could be obtained,
but electrical circuitry for the makeup pumps would
be complex and would require extensive amounts of
new cable.
He summarized: "In view of the above werecommend correcting the pressurizer level instrumentation rather than starting the second makeup

A review has been conducted of the pertinent sections of the B&W Reactor Coolant System Functional Specification for ANO-1 as requested by
AP&L. It was their concern that actual pressurizer
system performance did not agree with that statedi n the above document and B&W should clarify any
discrepancies. 50

Regarding the applicability of design to the ANO
operation, Winks continued:
The graphs of predicted system behavior for eachtransient were developed using a B&W hybrid
analog-digital computer simulation of the Arkansas
Plant. The simulator was subjected to a large
number of severe transients specifically to be conservative for subsequent design stress analyses on
RCS components and the transients were notdesigned to accurately represent actual plant performance. 51

pump "47

On July 24, 1975, R. Govers (B&W) forwarded to
Cavanaugh a report which elaborated on the subjectof pressurizer level. This report was prepared by R.
W. Winks, B&W Control Analysis Engineer. Govers
wrote: "Although the above reference [memo,
Govers to Cavanaugh, April 3, 1975] pointed outthat the loss of pressurizes level indication does notconstitute an unsafe condition, we are providing in
the attached report specific recommendations formaintaining pressurizes level indication above zero„~
inches.
Winks referred to two requests in his report:

Winks then referred to the three analyzed transients which he considered to be pertinent. The
most germane transient was the turbine trip followed by a reactor trip. The B&W analysis predictthat reactor pressure would level off at 1700
pounds per square inch and pressurizes level would
reach a minimum at 50 inches. Winks wrote thatthe feedwater flow modeling was "unlike the actual
sudden decrease and rapid increase in feedwaterflow generally occurring at the plant." 52 At no point
in his description of the system design did Winks
mention the "Design and Performance AnalysisPressurizer" (previously described), although there
was an oblique reference to the individual component functional specifications.
On August 5, 1975, Cavanaugh wrote D. J. Stoker, Project Manager, Bechtel Power Corporation:" We have reviewed your reference letter concerning
the increase of makeup flow to prevent pressurizes
l ow-level during a reactor trip. Based on Bechtel's
conclusion, we have determined that the problemsof piping, valves, and electrical circuitry needed toaccomplish additional make-up are more complex
53
than we can justify without more plant data."
Cavanaugh then requested that Bechtel investigate
and complete a proposed design to extend therange of existing level instrumentation by means ofa tap on the surge line.
On the same day, Anderson wrote to Cavanaugh,
commenting on Winks' recommendations. Regard-

Arkansas Power & Light Company has requested
that B&W define what recommended actions should
be taken to ensure that the indicated level of thepressurizer does not drop below zero inches on future major plant transients. An additional request
was made for B&W to clarify transient pressurizer
system performance presented in the Reactor
Coolant System Functional Specification i48comparison with actual pressurizes performance9

I n response to the first request, Winks recommended that the code steam safety valve be readjusted so that the minimum steam pressure
remained greater than 980 pounds per square inch
i n the steam generator. Additionally, he advised
AP&L to check the calibration of their pressurizer
level signal processing system. Regarding initiatinghigh pressure injection, Winks said that the operator
should no longer start the makeup pump, which isconnected to the normally unused injection nozzle,

195

i ng adjustment of the code steam safety valves, hesaid:

l ocate the lower level tap in the surge line and said
that construction would start upon Cavanaugh's ap-

proval.
On October 1, 1975, E. H. Smith, again contacted
Cavanaugh regarding the proposed modification.
He wrote that further analysis had disclosed a probl em:

We concur that it would be nice that T81e not fall
below 548°F. We do not concur that this can beaccomplished solely by resetting our main steam
safeties. Further, we believe that the blowback of
the main steam safeties has been optimized
through several attempts at resetting the amount of
blowback in the early phases of ANO-1's startup
test program. It is possible that some drift has
occurred since the last setting; but since resettingof blowback is largely a trial and error process, it isli kely that an attempt at change might worsen
rather than improve the present blowback.
The B&W letter fails to relate differences in F.W.
flow following the two trips discussed. It has been
noted that excessive F.W. flows following a trip candrive Tc down just as effectively as lowering turbine header pressure.
I t is felt that the ICS system design, which allows
a runback of F.W. after trip at normal tracking rate
(20°%/min.), is a major contributor to the excessive
shrink noted in our system. Even though the main
and to-load block valves trip closed rapidly on atrip, far too much F.W. flow is driven through thefull-open S.U. valves which will not modulate to oldt o-level limit on the OTSGs until the F.W. demand
signal is run back to below the to-level limit value.
This does not occur until 4 minutes following thetrip. Excessive F.W. flow also creates excessive
blow time of the M.S. safeties, which tends to lower
their lift and reset points.
The Operations group suggests that the S.U.
control valves be placed in manual and reduced to
10% demand (after the main F.W. blocks are
opened in the course of plant startup). If a trip
occurs, the F.W. flow will decrease at whatever rate
the main and to-load blocks will travel closed down
to the minimum pre-set value. Hopefully this would
provide data to demonstrate our contentions. A
long-term solution, such as instantaneous ICS runback on Rx trip, could then be pursued. 54

Specifically the results of our analysis indicate that,during the transient associated with reactor trip,
velocities in the pressurizer surge line may exceed
50 feet per second. These velocities would significantly affect the performance of the instrument,
causing it to give erroneous information.

Smith further mentioned Bechtel's investigation ofalternate methods for solving the problem.

On November 6, 1975, R. A. Govers (B&W) wrote
Cavanaugh expanding B&W's recommendation to
reduce the decrease in pressurizer level in a postreactor trip condition. 52 Govers recommended thatthe response of the turbine bypass valves and feedwater system be investigated further. Govers noted: "Further improvements to the ANO-1 feedwater
system can probably be made in the areas of optimi zed tuning or equipment enhancements.
Thisshould be pursued on a priority basis. B&W isprepared to assist AP&L in this investigation as atask under the Master Services Contract." 57
On December 10, 1975, Smith wrote Cavanaughon the level transmitter modification. Again, amodification was proposed that would provide erroneous indication, but Bechtel commented that thetransmitter would indicate very closely the minimumpressurizer level. Smith went on to say:
During the meeting [November 20, 1975] you indicated to us that the main object is to establish theelevation of the lowest point of the surge. This information is required in order to ascertain that thepressurizer level does not drop low enough as toresult in steam binding of the reactor vessel. If thel evel stays within the PZR [pressurizer] vessel, as
expected by B&W, and as would be deduced fromthe original curve, we believe that the suggested
solution is adequate to confirm B&W's informationand to establish the lowest point elevation. SS
On January 5,1976, Cavanaugh wrote Anderson:

With respect to pressurizer level instrumentation,
Anderson told Cavanaugh: "As pointed out, thesedifferences could be due to F.W. flow differences
between the two trips." 54 He said that the plantstaff had rejected the idea of starting an additional
makeup pump as a solution: "We disagree; we do
not want an unnecessary E.S. actuation to the same
extent as some don't want the unnecessary HPI54
He alsonozzle thermal cycles. See note below."
rejected increasing normal pressurizer level: "We

We have received a proposal from Bechtel tomeasure pressurizer level below the present rangeof our level indicators. This proposal states thatduring a rapid level change the indicator would give
erratic indication. However, during a downsurge
the indication would be lower than the actual condition such59that conservatism would exist in the instrument.

wholeheartedly disagree; this would eliminate any
possibility of surviving load rejection, or loss-ofAnderson concluded:"If
pumps runbacks." 54
operations were provided with wider range pressuri zes level indication, the standby E.S. pump wouldn't

Cavanaughthen asked Anderson to evaluate the59
proposal.
On February 17, 1976, Luken (B&W) wrote Cavanaugh:
At a recent meeting with representatives of AP&L
to discuss problems in plant response to large

54

be started."
On September 8, 1975, E. H. Smith, Bechtel Pro55
He enclosed
ject Engineer, wrote Cavanaugh.
drawings for the level transmitter modification to re-

1 96

upset transients, AP&L indicated a desire to change
the turbine bypass and steam code safety relief
valve setpoints for ANO-1. Presently, interaction
between these valves results in unsatisfactory utilization of the turbine bypass valve relief capacity,
thereby requiring the steam safety valves to relieve
steam for a longer period of time. This overheats
the valve seats lowering the safety valve reseatpressure and results in cycling which over cools
the reactor coolant system 0izer so that the level would have further to fall in theevent of a transient; or do nothing and tell the customers that even if level indication were lost, level
would still be sufficient. He noted that the third alternative would probably not be acceptable to thecustomers.
B&W notified AP&L of the level indication problem. The mention of possible pressurizes voiding
was not passed along. B&W's notification included
a recommendation to increase the operating level.
AP&L's Plant Safety Committee then evaluated therecommendation and determined that the change
had not been analyzed to their knowledge, that conditions could be worse than those assumed in
B&W's letter, and that loss of pressurizer level indication high might result from the change in operati ng level. It is interesting to note that AP&L apparently was unaware that the level tap had been
moved up until they received this B&W notification
on September 26, 1974, because the FSAR showed
an erroneous location for the level tap. (The rangeof the pressurizer level instruments was also erroneously listed in the FSAR.) AP&L has told the
SIG that they did not conduct QA audits directed toward the design or fabrication of the pressurizer
level instrumentation, and that upon discovery of the
reduced level range of the pressurizer level indicator,
they did not review B&W's documentation on thesubject.62
After receiving the AP&L evaluation, B&W withdrew its recommendation for increasing the operati ng level. B&W at this point did not acknowledge
the possibility of pressurizer voiding, but rather,stated that level would be available, even if indication was lost, to maintain pressure. B&W thenrecommended instructing the operators to take immediate corrective action following a reactor trip by
i ncreasing makeup flow.
A technical support inspector from Region II noted the low pressurizer level problem during his review of test acceptance criteria for minimum level.
Documentation reviewed by him indicated nocorrective action was possible to address the lowpressurizer level test deficiency. It should be notedthat the testing was performed under conditions(manual initiation of HPI) that resulted in higher pressurizer levels than would be experienced without
operator actions. The inspector also noted that theplant superintendent had already approved testingthat pointed out the deficiency. AP&L then received
a recommendation from B&W to change the test acceptance criteria. AP&L reviewed and approved
these test acceptance criteria changes, approving
operator actions to address the deficiency. In thenext inspection report, the NRC project inspector

Govers then suggested that the setpointchanged on the bypass valves and that the pressure setpoint be changed on some of the code
safety relief valves.
On October 21,1976, B. F. Hill, B&W Plant Equipment Services, sent a memo to R. J. Baker, E. L.
Logan, and C. E. Mahaney so that they could apprise Crystal River, Midland, and Davis Besse personnel of the pressurizer offscale indication probl em. Hill noted: "The 177 fuel assembly plants withthe pressurizer level indication range of only 320
i nches are susceptible to below zero level indications on reactor and turbine trips and load rejection
transients."
He recommended increasing theoperating pressurizer level from 180 inches to 200
i nches noting: "Any additional increase in level will
be in conflict with the assumptions employed in the
Anticipated Transient Without Scram study for the
NRC." He also recommended readjusting the safetyvalve blowdown noting:
The amount of blowdown of the steam safety relief
valves has been assumed to be 5% or approximately 50 psi for the safety valves with the lowest
setting (1050 psig). Measured steam line pressuresat operating plants of this type indicate that the actual blowdown is about 7% or 75 psi and even as
large as 8.5%. The minimum reactor coolant system average temperature following a reactor trip
should not decrease below 548"F and the minimum
steam generator discharge pressure should exceed
975 psig at the same time s1

Recapitulation and Analysis

A concern about preventing pressurizer level indication from going too low was expressed byMetropolitan Edison to B&W as a result of a generafor breaker trip test at TMI-1. B&W Lynchburg personnel evaluated this concern and noted that undercertain circumstances the pressurizer might be
voided altogether. They also realized that the problem of pressurizer level going too low, as it did at
TMI-1, might be more pronounced at certain other
B&W plants, including ANO-1 and Davis Besse,
where the lower tap was 40 inches higher than at
TMI-1. A B&W official (Karrasch) proposed three alternatives to deal with the latter problem: lower thetap; raise the normal operating level of the pressur1 97

closed out the item. The inspector noted that oneof the test acceptance criteria apparently had notbeen met because the high pressure injection had
come on, but he accepted the utility's explanationthat since high pressure injection had been initiatedmanually rather than automatically, the test was accepted.
The Plant Safety Committee (PSC) again reviewed the loss of pressurizer level issue, and again
classified it as an unreviewed safety question. The
plant superintendent noted that the issue probably
was not easily solved. He further noted that B&W
had stated that the pressurizer was sized to maintain RCS pressure even if the level indication was
l ost, but that it had never been shown to AP&L by
B&W that even if this occurred, the reactor core
would definitely stay covered. AP&L requested anevaluation to assure that if pressure dropped but
stayed above the high pressure injection setpoint,core uncovery would not result.
The Safety Review Committee (SRC) had previously reviewed Cavanaugh's memo to Anderson,
dated January 22, 1975, and found that the deficiency did not constitute an unreviewed safety question.
The SRC then reviewed the PSC decision that there
was an unreviewed safety question and cited confusion about the issue. The confusion apparently
resulted from little communication between the PSC
and SRC. Although there was a statement in the
SRC minutes that more information would be gathered and presented at the next SRC meeting, there
was no mention of the issue in the minutes of thenext meeting.
B&W responded to the request for further
evaluation by stating that the pressure could drop,
but would stay well above the high pressure injection setpoint. B&W reported that if the pressurizer
voided, core exposure would not occur becausepressure would drop rapidly to below the HPI setpoint and HPI would actuate automatically, providing
more water to the core. The concern about pincompresssion limits being exceeded as the result of
bypass valve malfunction, previously raised by Luken, was not addressed. Neither were the effects ofsaturation on system performance or operator
response addressed.
Section II, step 15 of B&W's design document," Design and Performance Analysis-Pressurizer,"
provides that: (1) the lower level indication tap mustnot be uncovered; (2) the resulting pressure mustnot be less than the high pressure injection setpoint
plus 100 pounds per square inch; and (3) if the pressurizer heaters are uncovered, the addition of
makeup water to cover the pressurizer heaters
should not cause the reactor coolant system pres-sure to decrease to less than the high pressure injection setpoint plus 50 pounds per square inch.
Thus B&W's response was not consistent with its
own design criteria.
The PSC then proposed that HPI be initiatedmanually following a reactor trip, but observed thatsuch a procedure created a problem with stresses
i n the HPI piping.
AP&L Plant Superintendent Anderson then discussed the issue with a B&W representative visiting
the plant and told him that AP&L was considering
whether the loss of pressurizer level indication wasa significant design deficiency. The B&W representative stated that additional work on the subject by
B&W would result in additional charges.
B&W conducted a study of the pressurizer levelproblem at ANO-1. This report compared performance at ANO-1 and TMI-1. The report maderecommendations to AP&L to limit the cooldown of
the primary system. B&W had been asked to conduct a review of their design requirements versus
the operating experience at ANO-1, but in fact theanalysis they performed stressed the difference inthe way the plant was analyzed as compared towhat was experienced in operation.
The AP&L plant staff reviewed the B&W recommendations made in the above referenced reportand rejected them, adding: "If operations were provided with wider range pressurizer level indication,
the standby (HPI) pump wouldn't be started."
AP&L contacted their architect-engineer, Bechtel
Power Corporation, and asked Bechtel to evaluate
i ncreasing the makeup capacity to prevent low level
during a reactor trip. This evaluation was done andsubmitted to AP&L. AP&L rejected this course because of Bechtel's description of the "complexity" ofthe modification. Bechtel was then asked to modify
the pressurizer level instrumentation to increase its
range. Drawings were prepared, but this modificalion was never implemented.
A meeting was held between AP&L and B&W todiscuss changes that would improve the pressurizer
level problems. It was finally decided to adjust the
setpoints on the bypass valves and safety valves.
Two years after the loss of indication problem
was identified, B&W initiated recommendations to
the Crystal River, Midland, and Davis Besse facilities
to address the issue.
Conclusions

1. Operating experience in B&W plants demonstrated that the system had been designed so that asystem component, the pressurizer, was not capable during certain anticipated operating tran1 98

sients of maintaining reactor coolant systempressure at a level that would prevent the reactor
from tripping or the emergency core cooling system from automatically coming on, or both.
2. Design changes in tap locations that were inconsistent with B&W's own design criteria weremade to the component at some plants in orderto save money. It appears that these savings
were trivial in view of the limited number of plants
i nvolved and the engineering costs associatedwith the change. This change worsened the human factors relationship between operators andthe equipment by causing pressurizer level indication (which operators rely upon to assure
themselves that the reactor core is covered with
coolant) to be lost for a substantial period of time
during anticipated operational transients. Apparently, the system's performance during operational transients was not examined to determine
the effect of this change prior to the change bei ng implemented.
3. In these plants, manual actuation of the emergency core cooling system or some other operator
action was required to compensate for thecomponent's limitations.
4. B&W was reluctant to accept its customer's initialconclusion that the level indication problem was asafety issue, not just an operational inconvenience. The supplier maintained that the problem
did not constitute an unreviewed safety question,and repeatedly tried to convince the customerthat additional operator action or changes in other parts of the system should be relied upon,rather than a design change. The matter was
eventually resolved by making changes elsewhere in the system.

5. The issue of the solution to the component limitation was discussed and ultimately resolved at
ANO largely outside the review process of the
NRC.
Recommendations
1. Systems controlling pressurizer level for anticipated operating transients should be distinctly
and separately operated from systems designed
to supply cooling water for loss-of-coolant accidents. Systems designed for loss-of-coolant
accidents should be designed to actuate in
response to breaks in the reactor coolant systemand should be designed to operate unabated until
their function is served.
2. The NRC should consider reviewing acceptancecriteria for startup tests performed and compari ng them to design requirements as required bydesign documents, to determine whether similar
component limiations exist.
3. Instrumentation should be installed to provide aclear indication to the operator of water level inthe reactor vessel.
4. The NRC should review the B&W pressurizer
design in greater detail to determine whether
equipment modifications (for example, greater
makeup capacity) are needed. (See also therecommendation in Section II.C.1.b.)5. The NRC should review the reliability of secondary equipment (main steam safety valves,
bypass valves, and feedwater systems) anddetermine whether existing equipment is acceptably reliable.

199

REFERENCES AND NOTES'Final Safety Analysis Report, Davis Besse, Sec.
5.5.10.1.
2
Memorandum from J. W. Anderson, AP&L, to W.
Cavanaugh, "Unit 1 Pressurizer Level Setpoint," February
6, 1975.
3Frederick dep. (July 23, 1979) at 183, 187 (Pres.
Com.).
4
Memorandum from R. W. Winks, B&W, to J. G. Mullin,"Information Requested by J. Creswell, USNRC,"
December 14, 1979.
5
NRC, "Staff Report on the Generic Assessment ofFeedwater Transients in Pressurized Water Reactors
Designed by the Babcock & Wilcox Company," U.S. NRC
Report NUREG-0560, Section 3-1 to 3-3, May 1979.
6
Metropolitan Edison Company, "Special Report Concerning the TMI-2 ECCS Actuation of 4/23/78," p. 6-11,
July 24,1978.
7
Memorandum from G. K. Wandling, B&W, to L. C.
Rogers, "Rapid Cooldown Transient of 4/23/78," May 8,
1978, at 6.
8
GPU Service Corporation, "TMI-2 Transient on April
23,1978: Task Force Report," at 25, August 1978.
9
The Babcock & Wilcox Co., Power Generation Division, "Nuclear Power Generation Department, Engineering
Calculations,
DesignandPerformance
AnalysisPressurizer (2A3-N, 2A391, 20R), September 1971, at 1-2.
10Babcock & Wilcox Calculation Data/Transmittal
Sheet, 32-953800, August 1978, at 4.
f1
Babcock & Wilcox Co., Power Generation Division,"Nuclear Power Generation Department, Engineering Calculations, Design and Performance Analysis-Pressurizer(2A3-N, 2A39a, 20R)," September 1971, at 2.
12

Id. at 3.
Letter from E. V. DeCarli, B&W, to E. A. Womack, J.
S. Tulenko, C. D. Morgan, and C. W. Pryor, B&W, Subject: I nternal Audit #70-Computer Programs, dated
September 25, 1979, (examined and on file in the offices
at Morgan,
Lewis & Bockius).
14
Babcock & Wilcox Co., NPGD Engineering Change
Authorization, B&W Engr. Change No: System Change
113, May 1970, at 1.
15
Babcock & Wilcox Co., CRAFT (Version 2) Calculation Computer Printouts (examined and on file in theoffices at Morgan, Lewis & Bockius).
16
Babcock & Wilcox Co., "Site Problem Report
Transmittal," SPR 322 Rev., September 1974.
17
Babcock & Wilcox Co., "Site Problem Report
Transmittal," SPR 322 Rev. 1, October 1974.
13

Memorandum from B. A. Karrasch, B&W, to R. G.
Luken, "Potential Pressurizer Response," September 18,
1974, at 1.
19
Id. at 1-2.
18

20
Memorandum from E. R. Kane, B&W, to J. N. Kaelin," Change to Pressurizer Level Control Setpoint," September 24, 1974.

21 Memorandum from J. N. Kaelin, B&W, to J. W.
Anderson, AP&L, "Increase in Pressurizer Level Setpoint,"
September 26, 1974.

20 0

22Memorandum (and attached document) from G. H.
Miller, AP&L, to J. W. Anderson, "Arkansas Nuclear One
Plant
Safety Committee Meeting," October 2,1974.
23
Memorandum from J. W. Anderson, AP&L, to W.
Cavanaugh, "Pressurizer Level Setpoint Change,"
October 15, 1974.
24Letter from W. Cavanaugh, AP&L, to G. M. Olds,
B&W, Subject: Arkansas Nuclear One-Unit 1 Pressurizer
Level Setpoint, dated October 18, 1974, at 1.
25
14. at 2.
26
Letter from J. N. Kaelin, B&W, to J. W. Anderson,
AP&L, Subject: Acceptance Criteria on Pressurizer Level,
dated October 29, 1974, at 2.

NRC, "Regulatory Operations Inspection Report No.
50-313/74-14-Arkansas Nuclear One, Unit 1," at Details II
paragraph 2.a, November 1974.
28
Arkansas Power & Light Co., "Minutes of Test Worki ng Group Meeting," November 20,1974.
29
U.S. Nuclear Regulatory Commission, "Regulatory
Operations Inspection Report No. 50-313/74-15Arkansas Nuclear One, Unit 1," at Details I paragraph 5,
January 1975.
30
Letter from H. A. Baker, B&W, to W. Cavanaugh,
AP&L, Subject: Arkansas Nuclear One Pressurizer Level
Setpoint, dated November 18, 1974.
31
NRC, "Staff Report on the Generic Assessment ofFeedwater Transients in Pressurized Water Reactors
Designed by the Babcock & Wilcox Company," U.S. NRC
Report NUREG-0560, Appendix S, May 1979.
32
Letter from W. Cavanaugh, AP&L, to G.M. Old, B&W,
Subject: Arkansas Nuclear One-Unit 1 Pressurizer FuelSetpoint, dated December 6,1974, at 1.
33
Memorandum from D. A. Rueter, AP&L, to W.
Cavanaugh, "Arkansas Nuclear One-Unit 1 Power Escalation Tests," December 11, 1974, at 2.
34
Cavanaugh Interview Transcript (Part II) at 12-13.
35
Anderson Interview Transcript at 13.
36
Rueter Interview Transcript at 10-11.
37
Cavanaugh Interview Transcript (Part II) at 14.
38
Memorandum from W. Cavanaugh, AP&L, to J. W.
Anderson, "Arkansas Nuclear One-Unit 1 Pressurizer
Level Setpoint," January 22,1975.
39Arkansas Power & Light Co., "Minutes of Plant
Safety Committee Meeting," January 28,1975.
40
Letter from W. Cavanaugh, AP&L, to R. Govers,
B&W, Subject: Arkansas Nuclear One-Unit 1 Pressurizer
Level Setpoint, dated March 3, 1975.
41
Arkansas Power & Light Co., "Minutes of the Safety
Review Committee Meeting," March 3,1975.
42
Letter from J. D. Phinney, B&W, to W. Cavanaugh,
AP&L, Subject: Arkansas Nuclear One-Unit 1 Pressuri zer Level Setpoint, dated April 3, 1975.
43Memorandum from W. Cavanaugh, AP&L, to J. W.
Anderson, "Arkansas Nuclear One-Unit 1 Pressurizer
Level Setpoint," April 15, 1975.
"Memorandum from J. W. Anderson, AP&L, to W.
Cavanaugh, "Arkansas Nuclear One-Unit 1 Pressurizer
Level Setpoints," April 30,1975 at 1.
27

45Memorandum from J. D. Phinney, B&W, to R. A.
Govers, "ANO Visit 5/14/75," May 19,1975.
46 Letter from W. Cavanaugh, AP&L, to D. J. Stoker,
Bechtel Power Corp., Subject: Arkansas Nuclear OneUnit 1, Increasing Makeup to Prevent Pressurizer Low
Level,
dated June 10, 1975.
47
Letter from E. H. Smith, Bechtel Power Corp., to W.
Cavanaugh, AP&L, Subject: Arkansas Nuclear One, Job
11406-035-Increasing Makeup to Prevent Pressurizer
Low Level, dated July 9, 1975.
48
Letter (and attached document) from R. A. Govers,
B&W, to W. Cavanaugh, AP&L, Subject: Arkansas
Nuclear One-Unit 1 Pressurizer Level Indication, dated
July 24, 1975.
49/d. at i.
50
1d. at 9.
51!d. at 10.
521.
at 11.
53
Letter from W. Cavanaugh, AP&L, to D. J. Stoker,
Bechtel Power Corp., Subject: Arkansas Nuclear OneUnit 1 Pressurizer Level-Transmitter Modification, dated
August 5, 1975, at 1.
54
Memorandum from J. W. Anderson, AP&L, to W.
Cavanaugh, "Arkansas Nuclear One-Unit 1 Pressurizer
Level Indication Following Reactor Trip," August 5, 1975.
55
Letter from E. H. Smith, Bechtel Power Corp., to W.
Cavanaugh, AP&L, Subject: Arkansas Nuclear One, Job

11406-041-Pressurizer Level Modification, dated September 8,1975.
56

Letter from E. H. Smith, Bechtel Power Corp., to W.
Cavanaugh, AP&L, Subject: Arkansas Nuclear One, Job
11406-041-Pressurizer
Level
Modification,
dated
October 1, 1975.
57
Letter from R. A. Govers, B&W, to W. Cavanaugh,
AP&L, Subject: Arkansas Nuclear One-Unit 1 Pressuri zer Level Investigation, dated November 6, 1975, at 2.
58
Letter from E. H. Smith, Bechtel Power Corp., to W.
Cavanaugh, AP&L, Subject: Arkansas Nuclear One, Job
11406-041-Pressurizer Level Transmitter Modification,
dated December 10, 1975, at 2.
59
Memorandum from W. Cavanaugh, AP&L, to J. W.
Anderson, "Arkansas Nuclear One-Unit 1, Pressurizer
Level Transmitter Modification," January 5,1976.
60
Letter from R. C. Luken, B&W, to W. Cavanaugh,
AP&L, Subject: Arkansas Nuclear One-Unit 1, Turbine
Bypass and Steam Safety Valve Setpoints, dated February 17, 1976, at 1.
61
Memorandum from B. F. Hill, B&W, to R. J. Baker, E.
L. Logan, and C. E. Mahaney, "Recommendations for
Avoiding Pressurizer Off-Scale Indications," October 21,
1976.
62
Reuter Interview Transcript at 12.

20 1

E INCENTIVES TO BEGIN"COMMERCIALOPERATION"
whether the reactor was unduly rushed into operation. 3 (Emphasis added.)

1. INTRODUCTION AND CONCLUSIONSThe Washington Star article also referred to thePennsylvania Public Utilities Commission's (PaPUC)
approval of a $49 million rate increase for Metroplitan Edison (Met Ed), noting that a portion of that
represented rate recognition of TMI reactor No. 2(TMI-2). 3
In its April 6, 1979, edition, The Washington Post
reported on a press conference held by the Ralph
Nader organization, Public Citizen, Inc., at which it
was charged that "Metropolitan Edison has reapedhuge tax benefits by pushing TMI-2 into service before the end of 1978. 4 (Emphasis added.) The
Washington Post article quoted Public Citizen as alleging that "the decision to put the unit into commercial operation was an economic decision that
disregarded a troubling record of mechanical malfunctions."4At the Public Citizen news conference on April 5,
1979, that organization released a 24-page study
entitled, "Death and Taxes: An Investigation of the5
I nitial Operation of Three Mile Island No. 2." The
paper, written by three attorneys from different
Nader organizations, concluded: "There is substantial evidence to suggest that the safety and reliability

One goal of the Special Inquiry Group (SIG) was
to determine "...the extent to which financial or tax
considerations influenced conditions in the plant inany way that might have contributed to the accident...."' This report discusses those considerations that are more commonly known as the "rushto 'commercial operation."' 2 At the same time, it attempts to examine the implications of this investigation for the regulation of nuclear powerplants.
The Allegations

The national media, approximately 1 week after
the March 28, 1979, accident at Three Mile Island(TMI), reported what was believed to demonstrate arush to commercial operation. For example, The
Washington Star began an article with the statement:

Metropolitan Edison Co.... was able to save millionsof dollars in Federal taxes by beginning commercial
operation of its [TMI] reactor No. 2 just two days
before the end of last year.
That savings... has raised questions as to203

of TMI-2 were far from assured when the unit wasplaced in commercial operation at 11:00 p.m. on December 30, 1978, but that the companies nonethel ess placed the unit in service at that time in orderto realize significant tax benefits." 5
At the press conference, Public Citizen also
released copies of a four-page letter sent to
President Jimmy Carter over the signature of Ralph
Nader and five others. The letter, copies of whichwere distributed to chairmen of certain congressional committees, repeated the allegations of the"Death and Taxes" paper.

An inference that these actions were taken inorder to obtain the incentives referred to in conclusion 1 can be derived from the fact that corporate officials charged with completion of TMI-2
were directly informed of those incentives andtheir relationship to a December 31, 1978 completion date.
3. Given the assumption that compliance with theregulatory program of the NRC indicates safe
construction and operation of a nuclear facility,
actions taken at TMI-2 to obtain certain financial
incentives did not compromise the safety of
TMI-2. This is a recognition of the fact that no
violations of NRC regulatory standards during theperiod from the granting of an operating license
to commercial operation of TMI-2 were detected.
For those individuals unwilling to accept theabove assumption, the question of whether theactions taken affected the safety of TMI-2 isunanswerable.
Without NRC criteria, there is no definition of"safe enough" against which to judge the adjustments that were made in the TMI-2 timetable. To
establish a standard that equates the fact thatthe accident occurred with "compromised safety"
i mposes an impossible post hoc standard uponli censees.
4. This investigation indicates that neither the financial incentives associated with construction of a
nuclear powerplant nor the impacts of those incentives on safety are fully recognized byFederal or State regulatory bodies. Consequently, regulatory requirements may create incentives
which could compromise a utility's commitment tonuclear safety.

Methodology

In investigating this allegation of "rush to commercial operation" in depth, the Special Inquiry
Group decided on the following approach: First, anattempt would be made to identify all relevant incen6
tives that existed for General Public Utilities (GPU)i n putting TMI-2 into "commercial operation" in
1978. Second, an investigation would be conducted to determine what action GPU took in constructi ng and testing TMI-2 so as to enable its completion
before the end of 1978. Finally, the ultimate question would be addressed: Was the safety of Unit 2compromised by any "rush" that was identified?
The report is structured to answer three questions that followed from this methodology: (1) Were
there incentives for completing TMI-2 before December 31, 1978? (2) Was deliberate action taken
to enable that completion? (3) Was the safety of
TMI-2 compromised by this action? A summary of
the conclusions prefaces the report.
However, this report is focused as much on thegeneric implications of the investigation for the nuclear industry as on the precise question of any
TMI-2 rush. These implications suggest the needfor a better understanding and a stricter regulationof the relationship between financial incentives andnuclear safety. Any attempt to read either the TMI2 investigation or the implications separately will notassist in a full understanding of the issues involved.

2. INCENTIVES FOR COMPLETING ALL WORKAT TMI-2 BEFORE THE END OF 1978
Turning to the first question of incentives, an attempt was made to fully explore each reason that
may have existed for completing all work (declaring
the unit in commercial operation) at TMI-2 before
December 31, 1978. The first two major financial
i ncentives-rate recognition and tax benefits-are
treated at some length. Other, lesser incentives arealso discussed in an attempt to present a full pictureof the situation facing GPU at that time.

Conclusions

1. Incentives did exist for completing all work andtesting on TMI-2 and declaring that unit to becommercial on or before December 31,1978.
2. Actions were taken at TMI-2 indicating that there
were time considerations which were linked tofinancial incentives. However, these actions affected primarily self-imposed company criteria,
and no adjustment of NRC-mandated safety criteria took place.

a. Rate Recognition of TMI-2
One of the incentives for putting TMI-2 into commercial service before the end of 1978 that the Spe204

cial Inquiry Group investigated was the utility rate
treatment consequences. 8 To fully understand this
aspect of the inquiry and its findings, a brief reviewof the fundamentals of rate regulation is necessary.
The three operating companies of GPU-Met Ed,
Pennsylvania Electric Company (Penelec), and Jersey Central Power & Light (JCP&L)-are all regulated utilities. 9 On the retail level, Met Ed and Penelec
are subject to the jurisdiction of PaPUC, as theirservice areas lie within the Commonwealth ofPennsylvania. JCP&L, however, is regulated by the
New Jersey Department of Energy, Board of Public
Utilities (NJBPU),
because it serves customers within
10
that State.
Because all three GPU companies are
i nvolved in interstate power transactions," they arealso subject to the regulation of the Federal Energy
Regulatory Commission (FERC), an agency of the
U.S. Department of Energy. 12
Leaving aside the broad authority of these
economic regulators until later in this report, the primary duty of each of these bodies is to regulate therates the GPU companies charge their customers toprevent exploitation of the "natural monopoly" utilities have in certain markets. The guiding principle inthat regulation, as stated in the Pennsylvania statutes, is to "provide for a just and reasonable returnon the fair value of the property used and useful inthe public service...." 13
Giving definition to that principle involves a fairly
complex process, but the essential point is that theutili ty generally does not by its own decision raise
its rates. Under the Pennsylvania scheme, the utility
notifies PaPUC of its intention to revise its rates andthen files a new tariff to accomplish that goal. 14
PaPUC then has the authority to suspend the effectiveness of the rate request for 7 months while it investigates the "justness and reasonableness" of therate request 15 PaPUC may then hold a hearing and,
if it finds the proposed rates to be unjust or unreasonable, it may then determine rates it considers"just and reasonable" and "fix the sameby order to18
be served upon the public utility ...."Part of the determination of the justness and reasonableness of the proposed rates is an examination of the rate base: that property the company
17
claims is "used and useful in the public service."A
new generating facility, such as TMI-2, would not be
18
earning "a just and reasonable return"for thei nvestors until PaPUC found it to be "used and use19
ful in the public service."
Determining the value of the used and useful property is also a matter for PaPUC determination.
Pursuant to a Uniform System of Accounts ' 20 utilities are allowed to capitalize the cost of borrowing
23
This commoney to build a generating plant .

ponent of the final costs of a unit, called allowancefor funds used during construction (AFUDC), canamount to a substantial portion of the final cost of aunit, especially toward the end of a project. Customers pay a "rate of return" on this capitalized debt
cost, just as they do on the concrete and equipmentof the facility.
As previously noted, the term "commercial operation" has a number of meanings. When expressedas "declaration of commercial operation," it is indicative of a utility accounting change that has ratemaking consequences. It is at that declaration thata new generating facility stops accruing AFUDC andi s placed in the "plant in service" account on theutility's books. 22 The regulatory impact of that shift
i s that the utility then looks to the State Public Utility
Commission (PUC) to provide a rate of return on aplant now claimed to be "used and useful in the
public service."
The risk nature of this declaration of commercial
operation should be obvious. There may be a considerable delay between the declaration-the end of
accruing AFUDC-and the first payment by customers toward a "used and useful" plant. During thisperiod, the utility is neither capitalizing the ongoingcosts, obtaining a rate of return on its investment,
nor recouping the normal operating and maintenance expenses associated with the unit. 23 This
period can be referred to as a "regulatory gap."
The goal of the utilities, clearly, is to minimize its
length; that is, it is advantageous for utilities to seek
to declare a unit to be in commercial operation (with
its associated accounting changes) as close as
possible to that24time in which final PUC action willbring rate relief.
The gamble in declaring a plant in commercial
operation is not eliminated, however, simply byprompt PUC action. If a serious problem with theplant should develop following this declaration, theshareholders might be exposed to the costs of curing the problem. Since AFUDC had stopped, such
repair work could not be capitalized into the value ofthe project for ultimate recovery fromthe ra25
tepayers, absent some further PUC action.
As can be seen, AFUDC provides something of asafe harbor for earnings, which utilities are reluctant
to leave until the smooth waters of a rate increase
are in sight. This security of capitalizing all costs
while minimizing risks causes regulators to be waryof the device. As discussed in detail below, chall enges are often made to the amount of AFUDC
claimed by a company in a unit. These challenges
are based on the premise that the company shouldhave completed the project sooner, reducing
AFUDC, and thereby reducing the valuation of the205

Kuhns then referenced an earlier letter to thechairman of PaPUC from GPU President Herman
Dieckamp, in which Dieckamp communicated the
problems GPU was having in the startup and test
program at TMI-2.32 In sum, Kuhns said:
What this boils down to is that, under yourCommission's Uniform System of Accounts, a generating unit must be transferred from CWIP to planti n service when, after a reasonable testing period, it
is ready for service even if there are some clean-up
construction activities remaining.33 (Emphasis added.)property upon which ratepayers will be forced to
pay a rate of return.
From a regulatory perspective, this is the importance of commercial operation. It was the possibilityof challenges to the timing of its declaration of TMI2 as being in commercial operation that caused the
GPU companies to be very specific in defining whenthat declaration would occur for TMI-2.26,27 As will
be discussed below, the GPU Service Corporation( GPUSC) even established formal procedures formaking the declaration.28 More importantly, Met Ed
had numerous contacts with PaPUC in which it
made certain representations, linking the declarationof commercial operation of TMI-2 to completion of
the test program at the unit.

Meanwhile, the Met Ed rate proceeding (R.I.D. 626)
was still before an administrative law judge. On August 30, 1978, the judge asked the parties todevelop and transmit suggested criteria for determining when a nuclear facility is "in commercial service.'"34 Met Ed responded with an exhibit, submitted by Robert Arnold, Vice President of Generation,that incorporated Section 14.1 of the NRC-mandated
Final Safety Analysis Report (FSAR).35,36 Arnold's" Schedule 14.1
covering statement stated:
describes the test program which must be completed prior to unrestricted operations."37
The final item in this sequence of Met Ed communications regarding the meaning of commercial
operation, was a letter dated November 30, 1978
from William Kuhns to the New Jersey Departmentof Energy, Board of Public Health (NJBPU). Kuhns
wrote, "Due to the extensive interest shown by the[Pennsylvania and New Jersey] Commissions in thestatus of Three Mile Island Nuclear Station Unit 2,
particularly as to when the unit will be ready to beplaced in commercial service, we are providing an
updated status on the unit."38 The status according
to Kuhns was that "[t]he full load generator trip will
mark completion of a start-up and test program
which has applied to all unit structures, systems andcomponents necessary to conduct commercial
operations. ...We believe that completion of thisprogram will provide assurance that the unit is capable of producing significant energy and is thenready to be placed in commercial service."38
Dieckamp summed up this history of communications on the subject of "commercial service:"

Met Ed recognized that the standard for declaring
TMI-2 in commercial operation was going to be
scrutinized even in PaPUC R.I.D. (Rate Investigative
Docket) 434, a proceeding in which TMI-2 was notallowed in rate base. On February 17, 1978, the administrative law judge (ALJ) there heard oral argument concerning the appropriate criteria for a declaration of commercial operation.29 PaPUC itself
heard oral argument on the matter on May 10,
1978.29
At a June 23, 1978, annual review meeting with
GPU officials, members of PaPUC apparently raised
the issue again, now looking toward the new filing(R.I.D. 626), which again proposed including TMI-2.
I n a letter dated August 11, 1978, William Kuhns,
GPU Chairman of the Board, wrote to the chairmanof PaPUC and stated that the criteria for determining
when a plant would go into commercial operation "is
not a matter of formula but is a matter of reasonable
judgment based on a consideration of all the pertinent facts."30 Some of the prerequisites cited by
Kuhns were that (1) tests had been run to demonstrate that "the plant as constructed is capable ofproviding the service intended," (2) startup testingand evaluation had progressed to the point where
portions of the unit were made available to the poolfor system dispatching, and (3) the plant was capable of producing sufficient energy "for use by the ratepayers."31
Special emphasis seems to have been placed on
the test program requirement. Kuhns noted that therequired tests were sometimes necessary to "assess the operational acceptablility of major items ofplant equipment and such tests have been the basis
for acceptance and supplier payments."31 Kuhns
also noted that these operational tests "include anumber of performance tests to be successfullycompleted before the Operating Permit [sic], issued
by the Nuclear Regulatory Commission, can become
effective for full power operation."31

I doubt that the declaration of the commercial inservice date of a particular generating unit has everreceived as much attention from so many sources
as was the case for TMI-2. We have sought tomake clear that our view of the appropriate time forthe declaration was the successful completion of along series of tests.... Those tests were outlined ina 25-page Exhibit No. E-21 presented by Mr. R. C.
Arnold in R.I.D. 62639 (Emphasis added.)
However, no matter how many communications
passed between GPU and the PUCs on this topic,
20 6

Met Ed's position remained the same: TMI-2 would
not be declared in commercial operation before all
FSAR-identified startup tests had been completed.
In Arnold's words: "We believe that under normal
conditions completion of this test program is aprerequisite for declaration of commercial operation.
We think it provides assurance that the plant is capable of producing significant energy
and is ready to
40of TMI-2. The basis of the argument accepted by
the judge was that the plant was going to be "usedand useful" within the test year under consideration.
Therefore, the company should be allowed to earn arate of return on that investment as of the date itgoes into commercial operation. On exception of
the PUC staff and the Pennsylvania Consumer Advocate, the commissioners rejected this approach,ordering instead that Met Ed institute a separate
proceeding when it was ready to include TMI-2 in
its rate base'45
This would necessitate a reexamination (retrospectively) as to whether the unit was "used anduseful." The consumer advocate even proposed amonth trial period following the declaration of commercial operation before PaPUC would
decide46

be placed in commercial service."

We have called this linking of the test program
and the commercial operation of TMI-2 a "commitment" made by GPU to PaPUC (and others). It
should be noted that, although some GPU officials
would agree with that characterization, 41 others in-sisted on distinguishing these "communications" as
not being commitments because the latter term
"tends to carry with it some kind of an implicationthat something would ... flow from the failure to42

whether TMI-2 was "used and useful."Penelec similarly sought inclusion of TMI-2 in its
rate base in a February 1, 1977, filing. Using thesame future test year as had Met Ed in R.I.D. 434,
Penelec argued that it should be allowed

i ng of the FSAR test program and the commercial
i nservice date of TMI-2 is an important issue in thisi nvestigation. It must be recognized that without thisvoluntary commitment, there is no PUC requirementthat all FSAR tests be completed
before a declara43
tion of commercial operation.
have made the report."

Semantics aside, the link-$64151000 as its 10% portion of TMI-2. 47 At thistime, Penelec was projecting that TMI-2 would become operational May 31, 1978.
In its rate case it48
was using a future test year,

which ran throughDecember 31, 1977. The administrative !aw judge
who heard the initial Penelec request decided that
this "post future test year adjustment" (that is, theinclusion of TMI-2 in the rate base on the assumption that Penelec would meet its scheduled operation date) was proper. PaPUC summarized the findings below:... they [the ALJs] found no reason to
exclude from rate base that property which is projected to be in service within a short period
after the49

A final point that should be noted regarding rate
regulation goes to neither law nor accounting, but tothe current regulatory system. Whether appointed
or elected, public utility commissioners do not gainwidespread approval by increasing rates. There isalso a desire on the part of PUC staffs, charged withrepresenting the public interest, to closely monitor
the practices and claims of utilities. Along with thenew offices of the consumer advocate, the PUC
staff constantly challenges the utility to demonstratethat it is entitled to its claimed rate relief. The effectand potential consequences of this regulatory environment are discussed at length below, but the
key point is that utility decisionmaking takes place inan environment of oversight and competing
demands.
With that understanding of the regulatory process and its pitfalls, this report turns to TMI-2 andthe attempts of the GPU companies to achieve
recognition for the unit in their respective ratebases. The processes in both Pennsylvania and
New Jersey, as well as proceedings before FERC,
must be examined.

Commission's Order here is entered."

The consumer advocate and PUC staff took exception to the administrative law judge's finding, andthe full commission agreed with their objections.
The Pennsylvania commission said:

We do not believe that, as an integral part of thisrate proceeding, Penelec should be given authorization to increase rates at some indefinite future
ti me. Instead ... the better procedure ... would be
to have the company make a separate filing to reflect its increased revenue requirement resulting
from the commercial operation of TMI-2. 5"

Meanwhile, JCP&L was having similar problems

before NJBPU commissioners. 51 Having proposed atest year ending March 31, 1977, JCP&L was forced
to concede that TMI-2 would not be in commercial

Both Met Ed and Penelec had sought inclusion of
TMI-2 in their respective rate bases long before adeclaration of commercial operation was made on
December 30, 1978. In (PaPUC docket number)
R.I.D. 434, Met Ed had convinced the administrative
law judge hearing the case to allow $165 931000 to
be included in its rate base as representing the cost

operation until "spring of 1978." 52

JCP&L thenjoined the other parties in its rate proceeding inagreeing "that it would be appropriate to determine
the company's revenue requirements associatedwith TMI-2 in the context of the overall results of52
operation

20 7

duringamore current test year."NJBPU then ordered one-half of JCP&L's investment in TMI-2 to be shifted from the proposed utility
plant in service account to the construction work inprogress (CWIP) account, where it would be allowed
to earn AFUDC from that date. 53 At the same time
the NJBPU ordered the Hearing Examiners Office tobegin a phase II proceeding to examine the "morecurrent test year" data that would involve TMI-2. 54
I n summary, all three GPU operating subsidiaries
had tried before TMI-2 was declared to be in commercial operation to have the unit included in theirrespective rate bases. All had been rebuffed by thecommissions in Pennsylvania and New Jersey,
despite the variety of arguments used by the companies.
However, the financial condition of Penelec
caused that company to file for a rate increase even
before its 1977 filing (R.I.D. 392) had been decided
by the PaPUC. On April 28, 1978, more than amonth before PaPUC refused recognition ofPenelec's share of TMI-2 in the rate base of R.I.D.
392, Penelec filed a tariff that would increase retail55
base rates by $75.4 million.
Using a future test
year that ended December 31, 1978, Penelec again
included TMI-2 in its rate base. 55 At this time,Penelec was predicting that TMI-2 would go into
commercial operation on May 30,1978. 56
The basis for Penelec's quick refiling was statedby PaPUC in its order as being "anticipateddeterioration in earnings ... attributed to the expected increase in capital, operating and maintenancecosts of the placement in service of the Three MileI sland Unit No. 2... nuclear unit, the Homer City Unit
No. 3 ... coal fired generation plant, and the Homer
City coal-cleaning plant." 57 On January 26, 1979,
PaPUC allowed Penelec to increase revenues by$64272000. 58 That amount was calculated on arate base of $1350000000-$175841000 (13%) of
which 58,59
represented Penelec's ownership of 25% of
TMI-2.
Acting on PaPUC's advice in R.I.D. 434, 60 Met Ed
filed a new tariff for PaPUC's approval on June 30,
1978.61 At that time, Met Ed was predicting that
TMI-2 would be in commercial service on Sep62
tember 1, 1978.
Of the $86 802 000 increase inrevenue sought by Met Ed, $68820000 represented "revenue requirements for Met Ed's fifty percent
ownership of Three Mile Island Unit No. 2...." 63
In R.I.D. 626, Met Ed proposed a test year ending
March 31, 1979. 64 Despite prior arguments in theproceeding by the Pennsylvania Office of the Con65
no one questioned the propriety
sumer Advocate,of including the vast majority of TMI-2 in Met Ed's
66
I ndeed, by the time
rate base in the proceeding.
of the drafting of the final PaPUC order, the commis-

sion could point to the fact that "Three Mile Island
Unit No. 2 ... went into service December 31,
67
1978."On March 31, 1979, PaPUC granted Met
Ed a revenue increase of $49178 000 on Pennsylvania jurisdictional operations. 68 This figure wascalculated on a total rate base of $1160000000,
which included TMI-2.
In New Jersey, phase II of the JCP&L proceeding
was decided on January 31, 1979. 69 The hearing
examiner noted that TMI-2 did not go into commercial service as expected in "the Spring of 1978." 70
However, since JCP&L had "waived the statutory
li mit on the suspension period until after TMI-2 wasplaced in commercial service," 71 and that had now
occurred, it was desirable to act on the matter.
NJBPU granted JCP&L a $33.8 million increase inretail rates, which reflected, among other things, theaddition to the "utility plant in service" account of$163 853000 for JCP&L's 25% share of TMI-2. 72
As previously noted, the State commissions do73
not have jurisdiction over interstate power sales.
To obtain rate increases for such interstate transactions (so as to reflect the placing into service of
TMI-2), the GPU operating companies filed proposed rate increases with FERC. On July 18, 1978,
Penelec filed for an increase of $7 587 000 from its
1 partial and 11 full requirements (wholesale) customers. 74 The Penelec case proposed a test year
ending June 30, 1979 and an effective date for therate increase of August 16, 1978. 74 Pursuant to theFederal Power Act, FERC suspended the effective
date of the rate increase to December 1, 1978. At
that time, Penelec would be allowed to collect its increase, subject to ultimate refund should FERC rulethat those rates were unreasonable. 75 This
proceeding was still awaiting76a FERC decision at theti me this report was written.
Similarly, Met Ed filed on November 13,1978. 77 It
sought a $4 772 496 increase from its five full andone partial requirements customers. 77 Met Ed useda test year ending December 31, 1979, and proposed an effective date for the rate increase ofJanuary 12, 1979. 77 As is typically the case, FERC
suspended the rates for 5 months, to June 13,78
This proceeding, too, is pending before
1979.
FERC.
Finally, on December 18, 1978, JCP&L filed for ani ncrease of $2136 351 to its all-requirements customers. 79 Using a test year beginning January 31,
1979, JCP&L sought an effective date of February
19, 1979. 79 FERC suspended that until July 17,
1979, at which time the increases would go into effect, subject to refund. 80 As with the other TMI-2
related cases, this matter is still awaiting a final decision by FERC. Although portions of the proposed
208

rate tariffs of the GPU companies have gone into effect 81 whether those companies will retain the approximately $14.5 million of increases sought has
not been decided.
I n sum, the GPU operating companies achieved
rate increases of approximately $165 million in
1979. 82 Although many factors were involved inthese increases, to a large extent they reflect theaddition of TMI-2 to the companies' rate bases andassociated regulatory treatment. 83
However, only a small percentage of these increases accrued to the shareholders of the companies as a return on their investment. 84 I n otherwords, the $165 million should not, ipso facto, beseen as an incentive for rushing TMI-2 into commercial operation before the end of the year, 1978.
Rather, to determine if the regulatory process was
an incentive for declaring TMI-2 to be commercial
by the specific date of December 31,1978, one must
examine what effect there would be on the pending
regulatory proceedings had that date not been met.
Throughout the previous discussion, there has
been an attempt to record the test year in each regulatory proceeding. A test year is a period of time
for gathering data relative to a particular utility's si-

rates 8 5 When inflation was low, the typical approach was to use an "historical" test year. That is,
the actual history of the utility would be examined
and future needs (revenue, rate of return) would bedetermined. However, with rising inflation andlonger regulatory proceedings, the historical test
year data was out of step with a utility's needs by
the time a decision was made. Hence, many PUCs
now allow a utility to use a "future" test year inwhich the utility predicts its condition at some year
ending in the future and regulators attempt to determine its needs on the basis of this future-looking
data. The goal, apparently, is to coordinate test
year and final action such that the granted rate increases reflect a company's picture at that timeand not some past data. 86
If a company seeks to present data regarding its
situation that falls outside the test year, it risks thedanger that regulators will not hear that evidence.87
If this item is a significant matter in the utility's rateplanning, such a disallowance could be damaging.
I n the cases pending before various regulatory
bodies involving TMI-2, 1979 future test years arefound in the Met Ed PaPUC proceeding (March 31,1979), the Met Ed FERC proceeding (December 31,1979), the Penelec FERC proceeding (June 30,1979), and the JCP&L FERC proceeding (January 31,1979). 88 In the NJBPU proceeding, although a March
31, 1977 test year was applicable to the phase I

209

proceeding, a "later test year with corresponding
adjustments of other specific data will be used forPhase II."89 I n other words, by stipulation in New
Jersey, the exact end of the test year was not ani ssue; it was to be made to correspond to the commercial operation date of TMI-2. 9°
The Penelec PaPUC proceeding also used a future test year ending on December 31, 1978. 91 Of
course, when Penelec filed for increased rates on
April 28, 1978, it was predicting that TMI-2 would be
i n commercial operation on May 30, 1978. 92 Thus,
the GPU operating companies at this time apparently expected TMI-2 to be included in the rate basesof the then-pending proceedings, as its commercial
operation date was within the relevant test years.
However, a number of problems 93 caused thepredicted commercial operation date of TMI-2 toslip substantially, and the 1978 test year in thePenelec case became significant to GPU. As GPU
President Herman Dieckamp told the President's
Commission on the Accident at Three Mile Island:
December 30 tended to be a significant date interms of having the plant in service during what,
under utility regulation, is called the 'test year.'That is the time period during which costs and expenses and investment are all normalized in orderpto
ensthaiformudset determine the rates thatwill be used in charging
to the customers. The test year tends to be significant because of things that occur outside of thetest year, it offers a legal opportunity to exclude
those costs. 94 (Emphasis added.)I n this explanation, Dieckamp did not distinguishbetween the Penelec case-the only proceeding inwhich this test year problem could be an issueand all other GPU proceedings.
Similarly, Robert Arnold did not distinguishbetween Penelec's situation and the other operatingcompanies' rate proceedings. Focusing on thesame point as Dieckamp, Arnold said in a deposition
that the test year problem was an incentive to becommercial in 1978. He explained:[ As] I understand it, that [being commercial in 1978]
would remove, as a matter of contention, whether
or not subsequent rates, which we had not received at the end of 1978, could properly reflect
TMI-2 ... I think it was our position that it could still
be included in the calculation of the appropriate
rates but the incentive from the company
standpoint-the only incentive that I know of-to
have it commercial by the end of the year was thatit removed that as an issue before the PUC. 95

I n sum, company officials arguably believed, as
they worked toward completing commercial operation at TMI-2 in 1978, that such completion would
eliminate an argument before PaPUC. In not stressi ng the fact that this was an issue only in thePenelec case, what the officials seem to suggest isuseful"). Regulators have an obvious incentive toli mit the amount of AFUDC that is capitalized into
the final cost of a unit. Such a limitation reduces therate base value of the project and directly reduces
the rates that the customers
must pay on the102
shareholder's investment.
Specifically, FERC attempts to limit accumulationof AFUDC during the test phase by specifying in In9D of its Uniform System of Acstruction
103,104
that "The utility shall furnish the Comcounts
mission with full particulars of and justification for
any test or experimental run extending105
beyond aperiod of 120 days for nuclear plant...."
I n otherwords, if a utility tests a nuclear unit for a period
greater than 120 days following initial synchronizaLion 1os the utility must explain why that has happened. The goal is to prevent a utility from abusing
the test period and its corresponding accrual of
AFUDC. 107 The penalty for running over the
120-day period, apparently, is the possible disallowance of that portion of AFUDC associated withthe longer-than-specified test period. Further,
FERC could require the utility to alter its books toreflect this reduced "cost" of the completed pro109
ject.
I n the case of TMI-2, as discussed more fully
later in this report, GPUSC was unable to complete
the testing at the unit within the 120-day period following initial synchronization on April 21,1978. 110 I nstead, when GPU realized the repair of the main
steam relief valves would certainly push them past a
120-day test program, GPU Comptroller EdwardmHolcombe wrote to the FERC chief accountant.
Holcombe asked FERC to ignore the initial synchronization of April 21 and instead allow a 120-day
test period to begin at the resynchronization
follow111
By telephone, thei ng repair of the steam valves.
head of the FERC Division of Audits replied to Holcombe that, although FERC would not allow restarti ng the test period, there was precedent for allowing
a plant to test for a period greater than 120 days "ifthere were good and sufficient cause for that. "112
GPU was proceeding, in other words, with the"exposure" that FERC could eventually deny a portion of AFUDC associated with a test period that ran
longer than 120 days. Each day beyond that period
before commercial operation created an incremental
i ncrease in that exposure.
Whether GPU officials were concerned with thepossibility of FERC disallowance because of Instruction 9D is difficult to determine. Robert Arnold said
he was unaware of FERC ever113
denying an extension
Similarly, Holcombeof the test program schedule.
said that, although there was some exposure fromthis issue, it was similar to that involved any time aa least-common-denominator type of planning.
That is, although Penelec owned only 25% of TMI-2,
and although the other operating companies (andPenelec at FERC) would not be risking test year arguments, if the plant came into commercial operalion in 1979, it was Penelec, the operating company
with the most exacting requirements, that concerned officials. The goal, it could be said, was todeclare TMI-2 commercial in 1978 to avoid this test
year argument.
That this type of reasoning is not entirely logicalhas been pointed out by GPU officials since the accident. It would be a very narrow argument to insist
that Penelec's $175 million investment in TMI-2
should not be considered in setting the utility's rates
because the plant went into commercial operation
on some day in January 1979, rather than before
December 31,1978. 97 In fact, it would have been adifficult argument for PaPUC to accept in light of thepersistent history of the GPU companies in seeking
to achieve rate base recognition of TMI-2. Had it
accepted the argument, it almost certainly could
have expected another rate filing.
Furthermore, planning the commercial operation
date on the basis of the Penelec test year end dateof December 31, 1978, might not even make financial
sense.
Speculating on that possibility, GPU
Treasurer John Graham said that it would appear
that the advantage of collecting 3 more months of
AFUDC (until the Met Ed test year date of March 31,1979) would outweigh the possibility of future litigation to contend denial of TMI-2 in the Penelec
rate
9 , 99base because it fell outside the test year. s
Nonetheless, the fact remains that TMI-2 was declared in commercial operation on December 30,
1978-1 day before the end of the Penelec test
year. Thus, the potential for argument on this score100
was eliminated.
Beyond this specific desire on the part of GPU toavoid an argument concerning the Penelec test
year, there were several other pressures on GPU tocomplete the project as soon as possible. That is,there were a number of regulatory devices that,
although not linking a declaration of commercial
operation to 1978 per se, made any earlier completion advantageous. These are examined as part ofthe collection of regulatory incentives.
Generally, all of these pressures flow from theaccounting change that accompanies a declaration
As previously disof commercial operation.
cussed, t01 that declaration shifts a new generating
station out of the CWIP account (with its accompanying accumulation of AFUDC) into the plant inservice account (with its accompanying regulatory
gap until the commissions find the unit "used and
210

114

new unit is placed in commercial operation.
Inaddition, he was confident that the test problems
would convince114
FERC of the need to go beyond the120-day period.
I n fact, GPU did not file a report with FERC explaining the longer than 120-day test period at TMI2115.116
Holcombe explained that at the time this report would have been prepared,
the March 28,
117
1979, accident occurred.
That report has now
been filed, and FERC is presumably examining therecord to see if the extension of the test program
was justified.
On the basis of past arguments, GPU could also
reasonably have been concerned in 1978 with arguments before the State Commissions that portionsof AFUDC should be disallowed for other reasons.
In October 1978, the accounting firm of Touche
Ross & Company prepared a report for the New
Jersey Department of Public Advocate, whichanalyzed a construction "slow down" at TMI-2 duri ng 1977 because of a "cash flow" problem within
GPU 118 It was the conclusion of that report that the
final cost of TMI-2 and its associated charges to ratepayers would
be higher because of the construc119-121
tion delays.
The Touche Ross report wasused by the consumer advocates in both New Jersey and Pennsylvania to argue for reducing theamount of AFUDC calculated into the cost of TMI2.122

From GPU's perspective, the possibility that suchan argument might be successful was a matter ofconcern. This concern was not mitigated by thefact that an argument of disallowing AFUDC as puni shment for an intentional delay had been unsuc123
cessful in past cases.
I n those cases, PaPUC
had decided that there was no evidence of intentional delay. Obviously, one means of limiting thepotential for these arguments was simply to minimize the time in which AFUDC was collected. As
GPU Treasurer John Graham said:
I guess given that context of the Touche Ross Report there was the potential for someone to makean attack on the time in the fall and winter of 1978
on the AFC [AFUDC] and I guess the loner you
accrued AFC the more potential developed.) 4Whether it was caused by an intentional slowdown,
defective valves, or something else, it would be to
the advantage of GPU to minimize the accrual of
AFUDC from a regulatory standpoint-even though
there might be advantages125
to GPU in the "safe harbor" previously discussed.
AFUDC could also be challenged on specific utility decisions. For example, the failure of the main
steam relief valves was attacked before PaPUC 126
asan example of poor management decisionmaking.
211

The Pennsylvania Office of the Consumer Advocate
argued that $12.2 million should be disallowed fromthe proposed rate base, so that the shareholders(as opposed to the ratepayers) would bear the costof the failure. 127 Such an argument was not unique;the valuation of TMI-1 was similarly reduced by the128
cost of replacing faulty concrete pourings.
Hence, any delay or any malfunction placed regulatory pressure on GPU to minimize the problem andthe time it took to develop a cure. Otherwise, thepotential for disallowance of a portion of AFUDC exi sted in the pending regulatory proceedings. To
prevent these arguments or the lengthening of theregulatory gap, GPU had an incentive to complete
TMI-2 as soon as possible. This is not inconsistent129
with a December 31,1978 target date.
An additional possible regulatory incentive existed for completing TMI-2 before December 31,1978:
the desire to maintain good relationships with thevarious regulatory authorities themselves. Regulated utilities deal in a long term relationship with PUCsand FERC. For that reason, GPU may have been
anxious to maintain good relationships with thesecommissions.
This situation is especially true for PaPUC, which
was perceived by GPU as being a "more formal" regulatory body. 130 I n the specific case of TMI-2, recall that GPU had committed itself to completion of
the specified test program
before declaring the unit
131
i n commercial service.
Had time required GPU to
declare the unit132
commercial before all tests had
been completed
to meet a December 31, 1978133
deadline,
GPU could have counted on possible
antagonism from PaPUC or its staff.
In addition, GPU was attempting to create afavorable impression before PaPUC in its adversary
proceedings. Knowing that the commercial operation of TMI-2 had become a significant issue in its
second 1978 proceeding (R.I.D. 626), Met Ed quickly
alerted by telegram the other parties (the staff, theOffice of the Consumer Advocate, et al.) that TMI-2
had gone into commercial operation while they werewriting their final briefs. l34 The record in R.I.D. 626
had been specifically left open to receive evidence
135
on the commercial operation of TMI-2.
Met Edpresumably wanted to be able to point to suchoperation at the final oral arguments
scheduled be136
fore PaPUC in the proceeding.
However, anothermalfunctionin early January prevented such a state137
ment.
The point is that for the sake of appearances andrelationships with PaPUC, it would have been advantageous for GPU to have TMI-2 in commercial
operation by the end of 1978. This would enable itto (1) comply with the previous commitment toPaPUC and escape future technical arguments and(2) make assertions at final argument in the ratecase that would have been more difficult otherwise.
As with the other incentives identified in this section,
it is difficult to determine whether these were concerns of GPU officials. Dieckamp has said theywould have been consistent with the kind of factors

basis. While the tax laws recognize this method of
calculating depreciation, it also recognizes so-called"accelerated methods," by which a business candepreciate an asset over a shorter useful life (i.e., ata greater amount per year) than it would be allowed
to under the straight-line method. One function of
the accelerated methods of depreciation is to pro-

Reviewing all of the incentives identified in thissection, it must be concluded that there were regul atory advantages for GPU in completing TMI-2 assoon as possible. Minimizing the possible arguments for AFUDC disallowance, attempting to retain
good relationships with the regulators, and improvi ng the ongoing rate proceedings were goals thatwere assisted by completion of the unit. However,businesses to constantly upgrade their production
capabilities with new equipment. If a businessmeets the criteria established by Congress and theInternal Revenue Service (IRS), it is entitled to thecredit and deduction.
Utilities, however, do have special tax problems.
Because they are regulated, special attention is paid
to the question of who benefits from tax advan-

GPU would recognize. 138

vide the same incentives as the ITC: to encourage

tages. 144 For example, PUCs sometimes attempt tothe only regulatory incentive that can be identified"flow through" the depreciation deduction utilities re-as being linked to completion of the unit by De-

ceive under so-called accelerated methods. 145,146
I n some ways, such regulation defeats the apparent

cember 31, 1978, is that previously
noted: the 1978
139
Whether that intest year in the Penelec case.

i ntention of Congress in providing the advantages tobegin with; a utility subject to a flow through orderwould not have the additional capital ,provided for byaccelerated depreciation to finance new construction. In some provisions of the Code, Congress has
i ntentionally drafted the law such that attempts by
PUCs to flow through tax advantages will preventthe utility from using that method of accounting.
147

centive alone would be sufficient to tempt a utility
away from its planned course of action requires
evaluation on the part of the reader. The contentionof the SIG is that, in conjunction with the incentives
discussed in the following sections, the Penelec test
year reinforced pressures to complete the unit in
the shortest possible time. It could, indeed, have
had an impact on GPU planning and operation.

Hence, there will be nothing to flow through.

Utilities also have special provisions in the tax
l aws themselves. For example, section 46 limits thequalifiedinvestments upon which a utility can claim
146

b. Tax Ramifications of Placing TMI-2 inCommercial Operation in 1978

ITC.
Other provisions limit the percentage crediton those investments by utilities. 149 While exact fig-

A second major incentive for declaring TMI-2 toures are not crucial, the concepts and criteria forobtaining these benefits are important.

be in commercial service in 1978 is alleged to havebeen the tax treatment that follows from that decision 1 40 The starting point to determine the impact

Section 46 (as in effect in 1978) allows a busi-

ness to receive a 10% credit on the value of certain
qualified investments (to a maximumof $25 000 and150of this incentive is to review the tax law as it would
have been known to GPU in 1978.

a percentage of the investment).

The Internal Revenue Code provisions of interest

ciation allowance sections of the Code.
The ITC
is designed to provide incentives for businesses toduring such taxable year."(Emphasis added.)

Section 167 allows depreciation treatment for "property used in the trade or business
152 or of property
held for the production of income."(Emphasis ad-i nvest in new plants and equipment. The goal is tostimulate the return of capital to a business both toupgrade the efficiency of theprocess and to provide
142
a boost for the economy.

A qualified in-vestment is defined by section 46 as a percentageof the property "placed in service
by the taxpayer
151

here are the investment tax credit (ITC) 141
and depre-ded.) It is apparent that both of these provisions re-

The depreciation al-quire that an investment or asset be more thanmerely existing; it must be involved in the businessof the taxpayer.
This concept is further elaborated in the IRS re-lowance is simply a recognition that the value of anasset deteriorates over time. A business taxpayer,
therefore, is allowed to deduct from its tax base a
portion of the value of the asset each
143 year as com-

gulations of the two applicable sections. IRS regula-pensation for this "wear and tear."tions define the placed-in-service standard of section 46 to refer to the earlier of two possible tax

This concept of depreciation as an expense of
doing business is normally taken on a straight-line212

years. The investment is placed in service during
either (1) the taxable year in which depreciation (persection 167) begins or (2) "the tax year in which theproperty is placed in a condition or state of readiness and153
availability for a specifically assigned function ...."The regulations implementing section 167 also
provide for depreciation to begin "when the asset isplaced in service." 1 54 The regulations direct that
I RS regulation 1.46-3(d) "shall apply for the purposeof determining"155
the date on which property is placedi n service ....
The point at which an asset isfirst placed in service, therefore, can control boththe ITC and depreciation treatment it receives in a
tax year.
Even these elaborations are inadequate in setting
forth the criteria as to when a nuclear powerplant
would obtain the tax provided by sections 46 and
167. The IRS has issued, therefore, several revenue
rulings (interpretive advisory opinions) that serve as
additional guides.
156
Revenue Ruling 76-428
allowed ITC anddepreciation treatment for a nuclear unit 157 that was
operational on December 23, 1975, even though it
was undergoing further testing to eliminate defects.
The unit at that point was at 17% of its rated powerl evel. The criteria used in determining that the unit
had met the placed-in-service test of the regulations
were the following:
1. All necessary permits and licenses had been approved;
2. Critical tests for the various components had
been completed;
3. The nuclear generating unit had been placed in
the control of the taxpayer by the contractor;
4. The generating unit had been synchronized into
the taxpayer's grid for its function in the businessof generating nuclear energy for the productionof income.
I n view of these attributes, Revenue Ruling 76428 concluded that the unidentified nuclear unit 158
was "in a condition or state of readiness... " 159 and,
therefore, placed in service in 1975.
One unusual aspect of the unit under analysis in
Revenue Ruling 76-428 was the observation that on
December 24, 1975 (the day after its status wasmeasured), "there was a partial shutdown of theunit ... due to an abundance of hydro-generated
electricity rather than to any problem concerning
the unit."160 ( Emphasis added.) This "lack of failure"
observation was emphasized more completely in a
recent revenue ruling. Revenue Ruling 79-98 basi-

213

cally concluded that a unit is first placed in service
on the date it becomes operational, not on the date161
it is accepted by the taxpayer from a constructor.
The criteria for this finding were similar to thoseused in Revenue Ruling 76-428. They were:
1. All permits had been obtained;
2. The unit had been synchronized with the grid;
3. All tests of components had been completed;
4. "And the unit was able to operate at its rated
capacity without failure even though undergoingtests to eliminate any defects and demonstratereliability."
An additional source of guidance from the IRS
with regard to proper tax treatment of a nuclear unit
came in a private "letter
ruling" (LTR), which was is162
sued on May 8, 1978.
Although letter rulings are
generally private and attempts are made to disguisethe taxpayer involved, in this instance the taxpayer
has protested the letter ruling determination and,hence, its identity has become known. Furthermore,l etter rulings may not be used as precedent in interpreting the 163
Internal Revenue Code or the applicableregulations.
However, since this ruling is directlyon point and is indicative of the thinking of the IRS in
this area, it is examined in some detail in this report.
Factually, Northern States Power Company (NSP)
had contracted for the constructionof its Prairie Is164
land I nuclear generating station.
NSP received
an operating license for the unit on August 9, 1973;
achieved criticality on December 1, 1973; and obtained
initial synchronization on December 4,
165
1973.
However, on December 17, 1973, a turbine
failure caused the unit to shut down, and the power
ascension
tests then in progress were not complet66
ed.i
The taxpayer (NSP) declared the unit
"operational" as of December 16, 1973, in a letter
dated 2 days later (1 day following the trip). At thatti me, Prairie Island 165
I had run at 50% of its capable
output for 30 hours.
I n a letter dated July 20, 1977, NSP asked for aruling on the question of whether Prairie Island I .
" was 'placed in service' during 1973 within the167
meaning of [the applicable regulations]."I n its reply of May 8, 1978, the IRS National Office ofTechnical Advice reached a negative conclusion onthat question. It reasoned that synchronization of agenerating unit with a grid alone
is not sufficient for
168,169a finding of placed in service.
I n the Prairie Island case, the IRS found "the testing of the nuclear
power generating facility for demonstrating its
specifically designed function, was abruptly ended
by a major component failure." 170 The letter ruling184

year 1978 drew to a close,
GPU's tax department
and comptroller began evaluating whether TMI-2
had been placed in service and would hence be eligible for ITC in 1978.
I nformation on the engineering status of the unit
as per the tax criteria earlier discussed was soughti n a number of ways. First, the comptroller had access to regular progress reports filed
by Robert Ar186
nold, Vice President of Generation.
The Comptroller, Edward Holcombe, and Arnold would also
talk by telephone about the progress of the unit
vis-a-vis the tax criteria . 187 Both the Comptroller
and Arnold also attended monthly meetings of the
GPUSC Board of Directors. At the December 1978
meeting of the Board of Directors, in fact, Holcombe
specifically asked Arnold whether TMI-2 would meet
the then-known tax criteria for being a plant placedi n service.188
The exact nature of the communication between
Arnold189
and Holcombe is subject to minor differences
but apparently Holcombe presented a
copy of Revenue Ruling 76-428 to Arnold so as to"...get his interpretation of the physical characteristics of the construction of the plant as towhetherthey met those (of the revenue regula190
tions]."
Arnold then reviewed Revenue Ruling
76-428 in the course of the meeting 191 andresponded verbally "that if they are the criteria thenTMI-2192
now meets those criteria and has for someti me."
It is, of course, possible to review the condition of
TMI-2 on December 17,1978, when Arnold gave thisopinion, as compared with the criteria of Revenue
Ruling 76-428. As will be recalled, that ruling set as
criteria the following: (1) all necessary permits andlicenses have been approved, (2) critical tests forvarious components have been completed, (3) the
nuclear generating unit has been placed in control of
the taxpayer by the contractor, and (4) the generating unit has been synchronized into the taxpayer's
grid for its function in the business of generating nu193
clear energy.
Briefly, there is no question that criteria (1) and( 3) had been met by GPU before December 17,
1978. Met Ed received its operating license fromthe NRC on February 8, 1978. The outstanding
items to be completed before moving to higher
power levels were all resolved by April 7, 1978,
when the NRC granted
permission to go to mode 1
194(power operation).
Similarly, there could be noquestion on December 17, 1978, that GPU had beenplaced in control of the unit. After the replacementof the constructorof TMI-2 with a maintenance con195
tractor in 1977,
GPUSC assumed the role of construction manager.

specifically challenged NSP's declaration of the unitas (commercially) "operational," stating, "Corporate
correspondence ... considered
the
plant
in
service ... with only 30 hours of operation in whichpower escalation was abruptly halted,
an obvious
171
condition belying operational status."
The importance of this letter ruling is in its specifi c linking of two events to tax treatment. Unlike previously reviewed IRS rulings, LTR 7833007 seems
to make completion of the power ascension test
program a prerequisite to a finding that the plant
was placed in service in the tax year. In addition,
the ruling links a declaration of commercial operation with tax treatment for the first time. 171, 72 Before
this ruling (as discussed below) there was great ambiguity as to the relationship between these two
events. In light of the inability to rely on LTR
7833007 as precedent and subsequent communications from the173
IRS on this subject, that ambiguity
may still persist.
The significance in reviewing this body of tax law
i s an attempt to understand GPU tax planning in
1978, especially as it affected TMI-2. Presuming
GPU personnel were aware of these decisions, 174
what planning was made to ensure proper treatmentof TMI-2 as consistent with the identified criteria?
Construction on TMI-2 began in 1969. Between
that time and the year in which the unit was placedi n service for tax purposes,175 several changes took
place in the tax laws. Most importantly, in 1975
Congress enacted amendments to the ITC provisionof the Code that allowed taxpayers to take "progress expenditure"credits on projects under con176
struction.
Inessence,this provided an alterna177
tive
to the original procedure of waiting until theyear the unit (in the case of a generating station)
was placed in service before
the entire amount of178
ITC would become available.
A portion of the construction expenditures associated with the TMI-2 unit were credited against
GPU taxes through this progress expenditure
method 1 79 However, a portion of the total cost of
the unit remained to be claimed in
the year in which179
the plant was placed in service.
I n other words,
some tax planning was necessary in 1978 to judge
whether TMI-2 would be placed in service for tax
purposes.
Determining when a plant is placed in service isgenerally not the same as declaring the unit in commercial operation.
Despite some recent confusion
180
apparently
it is possible that a unit
on this issue,
would be properly classified as placed in service
under the tax criteria before it would qualify for adeclaration of commercial operation-asthat term
181-183
As calendar
has been used before PaPUC.
214

However, the other two items in Revenue Rulinggenerating 105 MW. Although slightly less than the
76-428 deserve closer examination. Although Ar(arbitrary) 17% figure of Revenue Ruling 76-428,
nold apparently had no difficulty in understanding
TMI-2 generated a net of 47 MW on April 21, 1978,
the terminology, there is some confusion between
and could be argued to have "been synchronized
the criterion that critical tests for components must
. .. for its function in the business of generating nuhave been completed and the caveat appearing inclear electric energy for the production of income... ,"203
the same ruling that tax treatment was proper "eventhough the generating unit would198undergo further
Thus, an analysis of the four tests of Revenue
testing to eliminate any defects."(Emphasis adRuling 76-428 might have led Arnold to the concluded.)sion that TMI-2 was properly first placed in service
Early in Revenue Ruling 76-428, component teston April 21,1978: the latest date in which all criteria
i ng is equated with the fact that "All systems had
had been met. However, this ignores the caveat inbeen proven operational during the preoperational
Revenue Ruling 76-428, which recognized a shuttesting program." Thus, it would appear that thosedown as acceptable because it was due to "antests that must be completed prior to tax treatment
abundance of hydro-generated electricity203rather(component tests) are the same as those identified
than to any problems concerning the unit."(EmTMI-2 FSAR as the "preoperational test
phasis added.) The inference is that a "problem
i n the 197
phase."
That phase, according to the FSAR,
concerning the unit" might cause the IRS to scrutin"consists of functional tests and verifications thati ze carefully the performance record of the plantdemonstrate the components' ability to perform
during startup testing. Indeed, in a ruling that betheir design function(s), and ... demonstrate thecame available after this December 1978 timesystem's ability to operate197
as designed under actual
period, the IRS recognized as crucial the fact that
These preoperational
the unit in question was "able to operate at its rated
or simulated conditions."
tests are generally completed before initial fuel load,
capacity without failure while undergoing tests." 2041
which occurred at TMI-2 on February 11, 1978.
(Emphasis added.)
From a tax planning point of view, it would be imConversely, those tests to determine defects anddemonstrate reliability which the revenue rulings alpossible, of course, for GPU officials to be aware of
low to occur after qualifying for the ITC appear tostandards set in the future. However, as statedparallel those identified in the TMI-2 FSAR as theabove, Revenue Ruling 76-428 suggests that the"fuel loading and initial operation" testing phase ) performance of the unit is important. In addition, theThis phase of tests "ends upon completion of theprivate letter ruling previously discussed wasbrought to the attention of GPU financial people late
power escalation test program and designationof
199(Emi n the month of December 1978. That letter rulingthe unit as ready for commercial operation."
phasis added.) GPU declared the power escalation
makes it perfectly clear that deficiencies in the unit,
which require a cessation of the testing program to"test 200
program completed" on December 28,
effect repairs, can jeopardize a finding205,206
that the plant
1978.
In summary, the "component testing program,"
was placed in service in that year.
This
is
205
true, even if synchronization had been achieved.
which the revenue rulings require to be complete
Holcombe first became aware of LTR 7833007
before the granting of tax benefits, had been completed by GPU shortly after February 11, 1978. Bothwhen
an employee in the tax department, P. F. Da207l ey,prepared a memorandum on the subject.
Arnold and Holcombe, therefore, could reasonably
have concluded on December 17, 1978, that GPU
Daley's December 28 memorandum attached a
had met the (hot-functional) testing
requirements ofcopy of the letter ruling and noted that two tests
201
the applicable revenue ruling.
The program toremained in the TMI-2 power ascension program.
test for defects or reliability (the power ascension
He then stated:
tests required by the FSAR) appears to have been
[If] these remaining tests should disclose majorcompleted on December 28, 1978.2
faults which would prevent the unit from accomAnother problem in interpreting Revenue Rulingplishing its intended purpose, i.e., the generation of
76-428, as it pertained to TMI-2, is the requirement
electricity for the production of income, the 'in service' date could very well be 1979. A private ruling,of synchronization. This criterion is alternately
LTR 7833007,
dated May 8, 1978, supports this8
described as "initial synchronization and power
position
operation at203
greater than 17% of electrical capacityof the unit. ,TMI-2's generator was initially synDaley's concern was not an idle one. As discussed
chronized with the GPU grid on April 21, 1978 atlater, TMI-2 had already been through a major com209
6:29 a.m. The unit was then at 15% of its capacity,ponent failure that necessitated a 3-month delay.
215

To complete the test program in 1978, it was necessary to resynchronize the unit with the grid followingthat failure. This was successfully accomplished on
September
18, 1978, and the test program contin210
ued.
Daley's concern apparently was that a simil ar deficiency would be uncovered very late in thetest program in 1978. If so, the claiming of the investment tax credit in 1978 for TMI-2 could be jeopardized.
Holcombe was on vacation when the Daley
memorandum was written and distributed tomembers of the GPU financialgroup, including
211
President Herman Dieckamp.
Apparently, theconcerns of the memorandum were never communicated to the operating people and, in fact, on the
day Daley wrote his memorandum,
GPU declared its
212
test program complete.
Upon his return, Holcombe met with Daley andconvinced him that the situation of the plantin the213
letter ruling and TMI-2 were vastly different.
Holcombe then communicated his conclusions to Chief
Financial Officer Vernon Condon. As comptroller ofGPU, Holcombe then made the decisionthat TMI-2
214
had met the applicable tax criteria.
He did notseek advice of outside tax counsel because he felt
GPU had been through enough such determinations
215
that an inhouse decision was possible.
He did216
consult, indirectly, with the GPU general counsel.
From that point on, the tax treatment117
of TMI-2, as
per the 1978 consolidated tax return 'had beenmade.
I n its 1978 return, GPU claimed $46.5 million of
ITCs. Approximately $15 million of this218was due tothe placing of TMI-2 in service in 1978.
However,
because of limitation on the amount of ITC that a
taxpayer can claim, GPU was forced to take only an$18.5 million credit in 1978. The remaining $28 milli on was "carried back" to previous tax years andretroactively had the effect of reducing taxes inthose years. 219
An analysis prepared by Edward Holcombe 218
also indicates that the completion of TMI-2 enabled
GPU to obtain a $29 million depreciation deduction
on its 1978 income tax. 220 This had the effect of,among other things, reducing the 221
amount of incometax (before credits) by $13 million.
In bottom line figures, placing TMI-2 in commercial operation in December 1978 enabled GPU toobtain a $23 million refund, rather than pay $5.4
millionin taxes, for a total "savings" of $28 mil220,222
lion.
Because of the limitation on ITC thatcan be taken in 1 year, the GPU return showed a1978 payment of $4.7 million. Without TMI-2, GPUestimates
it would have paid $7.4 million in
220
taxes,or a difference of $2.7 million.
216

Although that $28 million represents an undeniable advantage for GPU, it must be kept in the perspective of a corporation that in 1978 had assets of
220,223$4.6 billion and $1.3 billion in revenue.
Furthermore, any analysis of benefits must be dynamic,
not static. Had GPU failed to meet the tax criteria
for placing TMI-2 in service in 1978, it presumably
could have done so in 1979, and all tax benefits thatwere obtainable in 1978 would then have become
available.
I n other words, it could be argued that the true
tax advantages of placing TMI-2 in service would
have simply been postponed 1 year. Hence, the real
benefit of completing TMI-2 was that GPU gained
the use of the money for 1 year (1979) that would
have otherwise been paid as taxes. The money
gained is not just the $2.7 million reduction in taxes
actually paid but would also include the tax effectsof the $28 million in ITC that GPU carried back toprevious years. Presuming those carrybacks reduced past income taxes paid, GPU would receive arefund, which could be put to use within the corporation. In addition,224
because it used the modified
half-year convention,
GPU would also have thebenefit (again, for at least 1 year) of the tax effect ofapproximately$29 million worth of deprecia225,226
tion.
The value of this "interest free loan" 227 to GPU
must be valued against what the cost of that money
would have been in the marketplace-presuming
228
GPU had a need for such borrowing in 1979.
In
extremely rough terms, using a 1979 interest rate of
10%, this analysis would yield a229
final "cash flow" advantage of $2.9 million to GPU.
Again, this amount must be measured against
the total needs of a corporation the size of GPU.
Although an advantage, the tax incentives for completing TMI-2 were not large, in a relative sense.
c. Other Financial and Nonfinancial Incentives
Beyond the major incentives related to rate
recognition, reduction of Federal income taxes andthe potential disallowance of AFUDC by FERC, otherfinancial and some nonfinancial incentives could
have contributed to the decision to declare TMI-2 incommercial operation on December 30,1978.
Although not one of these items by itself appears
to be an overriding incentive, they all add to thebenefits received for bringing TMI-2 on line either by
December 31, 1978, or as soon as possible after thelongstanding May 31, 1978, forecast completion
date. As Dieckamp said in speaking about payments to the Pennsylvania-New Jersey-Maryland

( PJM) Pool, "I am sure all nickels add up to dollars
and what have you, but I would not in my mind230
have
identified that as an overriding consideration."

Schedule 2.01(b) requires that forecast requirements be determined annually, before April 30, forall of the planning periods included in the long range
PJM plan and that unless otherwise agreed to, theforecast requirements for the "three full planning
periods following such annual determination shall beconsidered 235
firm and not subject to redetermination
thereafter."
Each PJM member must submit to
PJM its plans for carrying its forecast obligation either through (1) installation of generating capacity;(2) purchases of capacity and energy, either fromwithin or outside the pool; or (3) purchases of capacity from other PJM members who 236
have capacity inexcess of their forecast obligation.
Further, thePJM Agreement
specifies
the
price
for
deficiency
237,238
purchases.
The rate in effect for the period
June 1, 1978237,23s
through May 31, 1979, was$22.63/kW/yr, 237,239calculated on a daily basis,or $62/MW/day.
Commitments of individual PJM members becomel ocked as much as 3 years before a unit is forecast
to become part of a member's installed capacity.
Schedule 2.01(e) requires that the plans submitted
by each PJM member for a planning period "shall beconsidered firm commitments as of a date twoyears prior to the beginning of such planning
period."Because the PJM planning period is "the twelve
months beginning June 124
and extending through May
31 of the following year," o the firm commitment requirement
means
that generating capacity
scheduled to become installed capacity by May 31,
1978 (as an example), is a firm commitment as ofJune 1, 1975 (2 years prior to the June 1, 1977,
through May 31,1978, planning year).
The PJM planning period ends on May 31 because the pool as a whole is a summer peaking
pool, that is, the maximum load on the PJM pool occurs in the summer, defined as June through September. A winter peak is similarly defined as theforecast maximum 1-hour load during the period December through March ' 241
Clearly, the early estimated inservice dates for
TMI-2 coincided with PJM planning periods.
Perhaps the earliest estimate was made in June
1969,242
when an inservice date of May 1973 was forecast.
The date subsequently was revised in 1year increments to May 1974, 1975, 1976, and 1977,
and in243
September 1974 it was again revised to May
1978.
All of these inservice date changes weremade before or just after the beginning of the 3year period when the otherwise unrevised datewould have become a "firm commitment" underschedule 2.01(e) of the PJM agreement. For example, prior to the revision in September 1974, thePJM Power Pool

The entire GPU system, including Met Ed, is partof the Pennsylvania-New Jersey-Maryland Interconnection. Often referred to simply as the PJM Pool, it
coordinates, or pools, the electric bulk power facilities of all PJM members and operates those facili231
ties as if they were a single system.
In a letter dated January 2, 1979, from GPU tothe manager of PJM, GPU reported that "Effective
2300 hours on December 30, 1978, Three Mile Island $t2 was made commercial for 880 and 906
MW Summer and Winter rating, respectively. This
increases the total GPU installed capacity from
6845 to 7725 MW Summer rating and from 7375 to
8281 Winter rating." The letter suggests that an incentive existed for bringing TMI-2 into commercial
operation to increase the "installed capacity" of the
GPU system. This requires some understanding of
the PJM system.
PJM involvement in the planning for TMI-2 probably goes back at least to 1967 when the "PJM
member companies entered into a service-reliability
compact known as the Mid-Atlantic Area Coordination Agreement (MAAC). It calls for planned new
additions ... to be submitted to the MAAC Executive
Board
for review by its Area Coordination Commit232
While this long range planning is coordinattee."ed by MAAC, the PJM Agreement requires PJM
members to make firm commitments of capacity andto cooperate with other PJM companies regarding
planned outages, transmission facilities, and other233
All the GPU operating companies (Metmatters.
Ed, Penelec, and JCP&L) are treated as one entity in
PJM operations. In fact, article 2.1 requires the GPU
subsidiaries to have in force, arrangements for the
allocation of GPU's PJM obligation.
PJM capacity planning begins with setting the requirements for PJM and then allocating the definedrequirement to the pool members. The agreement
provides, "The electric generating capacity requirement [of PJM] shall be an amount of capacity sufficient to carry the load, permit maintenance and provide reserveadequate to achieve a high degree of234
reliability."
The PJM management committee
forecasts this electric generating capacity requirement (called the forecast requirements, which is expressed in megawatts) for future planning periods
and sets the equitable allocation of that requirement
for each PJM member (each member's portion iscalled its forecast obligation).
217

forecast inservice date was May 1977. GPU would
have had to make the May 1977 date a firm commitment by June 1, 1974. Instead, in September 1974,
the inservice date was changed to May 1978. Because the May 1978 date was not again changed
until March 1978, 2 as of June 1, 1975, there was afirm capacity commitment to PJM to bring TMI-2
i nto installed capacity by May 31, 1978. Of course,
the May 31, 1978 estimated inservice date would
also mean that TMI-2 would be available to meet theactual summer 1978 peak load.
Because the May 31, 1978, date for TMI-2 hadbecome part of GPU's firm capacity commitment to
the pool, GPU incurred financial penalty for missingthat installed capacity commitment. Over the 6month period June 1-December
245 31,1978, the total ofthat penalty was $7 383 332.
According to Robert H. Sims, GPU's representative to PJM, the PJM pool as a whole has had excess installed capacity since 1972, 2 but GPU, according to their 1978 forecast, wasshort of their247,2acapacity commitment to the pool.
s Had TMI-2
been available as projected in June 1978, GPU
would have paid no capacity penalty to the PJM

ture.251 John Herbein recognized this situation
when he testified:
We commit a certain amount of capacity to the[PJM] system and to the extent that we don't meetthat capacity why then we are subsequently penalized. So it's to our benefit to declare the unit commercial at some specific power level that we arereasonably confident we can make on a regularbasis. And in turn, that means that the252
plant has
got to operate at an acceptable capacity.

Robert Arnold, Vice President of Generation, feltthat once the May 31 date was missed, there was
no incentive in terms of the PJM Pool until perhaps
the end of the following PJM planning period. Arnold said, "I expect that once we identified that wewere likely to miss that date, [May 31, 1978] that itprobably was diverted a full year or postponed a fullyear interms of a commitment on planning to the263pool."
I n sum, GPU's attitude toward the PJM commitment, as stated 254
by GPU President Herman" when we declare a plant
Dieckamp, was thatcommercial, it is made available to the system
dispatchers to call upon that plant for generation
when it is needed. So it is, in effect, officially madeavailable to provide power to the pool, but thatis... not a terribly significant thing."
Although the PJM penalty appears large, and may
be an incentive to complete a unit as close to its
committed date as possible, there apparently were
no PJM incentives for declaring TMI-2 commercial
by the end of 1978 per se.

pool. 249

Assessment

Although GPU had this incentive to complete
TMI-2 as soon as possible, apparently there was little, if any, pressure from PJM to bring TMI-2 into
service specifically by December 31,1978.
To the extent that TMI-2 would be a low costunit, the PJM pool and GPU would both benefit nomatter when the unit was brought into service. PJM
had excess capacity and because PJM's peak load
is in summer, there would be little pressure from thepool to bring TMI-2 into service in December. Testifying in a Davis Besse hearing, one consulting engineer said that interconnected utilities are not anxious to see an untested generating unit declaredcommercial. He went on to state:

Corporate Capital

Another possible incentive considered by theSpecial Inquiry Group was the influence, if any, of
TMI-2's commercial operation on GPU's ability toraise money. Utilities constantly need capital to pay
for the construction program, meet sinking fund obligations, and refinance maturing indebtedness. The
sources of capital to provide the total funds generally are internal funds generated by the company's
operations, the sale of common and preferredstock, the issuance of first-mortgage bonds and debentures, and short term sources such as issuanceof commercial paper or bank loans.
In mid-October 1978, GPU forecast 1979 capitalrequirements of approximately $537 million, of
which the largest single item was $135 million for
construction
costs of the Forked River nuclear
255
plant.
The financing of the $537 million was
forecast to come primarily from internal funds, with
the need to issue approximately $156 million longterm bonds and also sell some preferred and common stock as well as issue some commercial paper.

To ask interconnected neighboring utilities to accept an untested unit as operational is to ask themto support the reliability of service of the owning
utility. The untested unit ... would probably be lessreliable than more mature units [and] the neighbori ng utilities would be providing the reserves tobackup the unilt -in question. This is not only unfair
but I am sure it would
250 not be acceptable to theneighboring utilities.

An individual utility member of PJM encountering aforced outage on a plant that has been in service forat least 1 year, also suffers in terms of having to
supply larger total capacity requirements in the fu21 8

Ordinarily when a company issues debt or preferred stock, limitations or conditions are put on thei ssuance of additional debt or preferred stock in the
future. This was the case with the GPU companies.
As Met Ed's form 10-K submitted to the Securities
and Exchange Commission for the year ended December 31, 1978 states, Met Ed's indentures and articles of incorporation "contain provisions limiting
the total amount of securities evidencing funded 256
indebtedness which the Company may issue...."
These limits deal with coverage ratios, that is, theamount by which earnings exceed interest charges
and ratios of short term debt to total debt or capital.
I n other words, the limiting factor on the issuanceof new bonds or other capital financing is the earni ngs of the company. However, once TMI-2 wasdeclared in commercial operation, large depreciation
expenses began to reduce net earnings. Of course,
the commercial operation declaration also signaled
the cessation of the noncash AFUDC earnings related to TMI-2. Therefore, the commercial operation
declaration by itself was not sufficient to increase
earnings; rather, the rates regulated by the State
PUCs had to be increased to have that effect. This
meant securing an order bringing TMI-2 into the ratebase. Since rate case matters have been discussed
previously, 257 no further elaboration will be presented here.
As Met Ed's form 10-K explains the situation:"Since under the Company's indenture and articles
of incorporation such ability [to issue new securities] is measured for a consecutive twelve month
period during the fifteen months immediately
preceding such issuance, it is to be anticipated thatthe coverage ratios may deteriorate and might be afactor in the absence of adequate rate reli miting258
lief."
Under the indentures of some electric utilities it ispossible that a new electric plant becomes bondable, that is, the plant is eligible to serve as security
for the issuance of first-mortgage bonds, only when
the plant is placed in commercial service. If thiswere true for GPU, then the commercial operation
declaration would have allowed significant increases
i n the debt GPU could issue. However, John Graham testified that, "under our indentures, the declaration of the plant as being in commercial service
is not material to the issue of bondability" because
the indentures were amended in the early 1970s toallow 259
the bonding of construction work in proHe further stated: "We had bonded TMI
gress.
as it met the criteria of the indentures and whether
it's in commercial service or not... simply doesn't
make a difference for purposes of certifying bond260
able property additions to the various trustees."

Before the December 30, 1978 commercial
operation date, $654 million was certified, an increase of $83.5 million that apparently was independent of the commercial operation declaration. 261
High-quality bond ratings by bond rating companies allow a company issuing bonds to do so atinterest rates lower than those for lower quality
bonds. The effect of even small reductions in interest rates can amount to millions of dollars overthe life of a large bond issue. Did the TMI-2 commercial operation declaration perhaps serve to improve or maintain GPU companies' bond ratings?
At the end of 1978, the first-mortgage bond ratings of the GPU subsidiaries were as follows: Met
262
Ed, "A;" JCP&L, "Baa;" and Penelec, "A."
Moody's explanation is that "A" bonds are considered "upper medium grade obligations," while
263"Baa" bonds are "medium grade" obligations.
The highest Moody's bond rating possible is "Aaa"and the lowest possible is "C."
Certainly delays in nuclear plant operation canharm a company's bond rating. The New YorkTimes reported that Moody's, a bond rating service,
had lowered Long Island Light Company(LILCo)264" Moody's
publicly held first-mortgage bonds.
said the action reflected the company's [LILCo's]l ow level of internal cash generation, which resulted
from the constructionof the company's Shoreham
265
Nuclear Station."
Before the LILCo decision, Moody's stated thatan indefinite delay in TMI-2 in late 1978 would havecaused Moody's to seriously review Met Ed's rati ngs. 266 However, at that time there was no indication of an indefinite delay in declaring TMI-2 commercial. Standards & Poor's (S&P), another bondrating service, saw it as inconsequential if TMI-2
went into commercial operation December 30,1978,
or January, February, or March 1979. S&P ratings
are planned to be long term ratings267
and should
override any temporary adversity.
AnotherMoody's employee said succinctly that if Met Ed's
financial condition and thus their bond ratings weredependent on the commercial operation declarationby the end of the year, then most likely268
the rating
would have been in jeopardy long before.
Evidently the timing of the commercial operation
declaration, as long as it was in sight, was not crucial to maintaining or improving the bond ratings ofthe GPU companies. John Graham, GPU Treasurer,
felt that the rate case was the important factor inbond ratings. He said S&P was ready to upgrade
Penelec's rating "and a delay in the rate case269
may have delayed our ability to accomplish that."(Emphasis added.)219

Because the annual report was not published until l ate February or March 1979, information about
the completion of TMI-2 could well have been included in the report even with a commercial operation date several weeks into 1979. The annual report, therefore, was not in itself an incentive forcompletion of TMI-2 in 1978.
Nonetheless, there is at least one element offinancial reporting in the 1978 annual report that did
have a December 31, 1978 cutoff date. To show275
ratherTMI-2 as part of utility plant in service
than as CWIP required a declaration of commercial
operation by December 31. Although not a major incentive, this has some appeal for the bulk of GPU
shareholders. Otherwise, the reported financial
results would show more than $1 billion as CWIP outof a total of $4.1 billion in net utility plant.

Assessment

The ability to raise new capital is tied not to acommercial operation declaration but to rate cases.
Even underlying aspects such as determinations ofbondable plant and the setting of bond ratings did
not hinge on a commercial operation of TMI-2.
Thus, the rate cases are the areas of possible incentive, as enhanced by the ability to raise newcapital. As Graham said, commercial operation"takes away some financing capability because theloss of the [AFUDC] earnings has the effect of
reducing coverage until you get your rate order andbegin to recover the cash earnings at which time
there is an improvement in financing capability. H270
Nonfinancial Incentives

Although not quantifiable, some nonfinancial
benefits existed for declaring TMI-2 to be in commercial operation by the end of 1978.
An annual report, although addressed primarily toshareholders, serves to communicate company progress to a wide spectrum of interested parties. The
GPU Annual Report for the calendar year 1978
refers to TMI-2 this way:

Assessment

These benefits are not quantifiable. Financial
analysts are generally concerned only with whether
a plant is in rate base, not with how it is presented
i n the annual report financial statements. The reporting of a significant milestone does, however,hold some goodwill benefit. While the corporate attitude to achieve certain objectives is not unique tocompleting nuclear units, the implications in the nuclear industry are different.

The end of 1978 saw a major milestone i n the history of General Public Utilities. With commercial
operation of the second unit on Three Mile Island,Pa., the Company completed a $1.1 billion, two-unit
nuclear271 station (TMI-1 and TMI-2) started a decadeago. ( Emphasis added.)

NRC Requirements-Guidelines on Time forCompleting Test Program

Previous sections examined the possible incentives for bringing TMI-2 into commercial operationthat may emanate from the financial and some nonfinancial aspects of GPU's condition. There may
also be some incentives arising from requirements
or informal guidance of the NRC.
There is an NRC regulatory format in which thisprocess takes place. Following issuance of theoperating license, a licensee must proceed throughsix "operational modes," obtaining approval from the
NRC at each level, before a unit is approved to generate commercial amounts of power. The sixmodes are: operational mode 6 (initial fuel loading);
operational mode 5 (cold shutdown); operationalmode 4 (hot shutdown); operational mode 3 (hotstandby); operational mode 2 (startup; criticality);
operational mode 1 (power operation).
Each license specifies uncompleted action (at theti me of the operating license) which must be completed before authorization will be granted toproceed to the next Operational Mode. On the report of the NRC Office of Inspection and Enforcement (IE) that a licensee has fulfilled the require-

Met Ed's Annual Report similarly states, "For
Metropolitan Edison Company, 1978 will remain amemorable year, chiefly because of the completionand entry into commercial service of the second
Three Mile Island ('TMI') nuclear station."272
No one can fault the utility for reporting the progress made. The commemorative remarks, however, reflect the attitude existing in GPU in 1978, as
can be seen by this statement by John Graham:"There's no question but that completion of TMI-2
was a major corporate objective simply because it
was being built for a longer time, was a major investment, would produce a lot of energy at a low
fuel cost, andwas an awfully good thing to have273
behind us."
Graham is not alone in recognizing the attitude atthat time. Robert Arnold, in talking about the completion of the TMI-2 test program in late December
1978, said that although he did not instruct people
to come in over the Christmas weekend, many may
have 274
because of "the attitude that existed at thatti me."

220

ments specified in the license, the responsible NRC
official will issue the necessary authorization letterto the licensee.
It is evident from depositions, however, that NRC
guidance beyond this mode system is vague andnot well understood either within the NRC or by
GPU personnel. Herman Dieckamp, testifying before PaPUC after the accident, said, "The NRC has
pointed out that the timing of the beginning of physical operation of a nuclear generating unit and thecircumstances of such operation are governed by
the NRC operating license and have nothing to dowith whether the unit has been declared to be in' commercial service.'" 276 This statement accurately
characterizes the situation in that no NRC requirement is explicitly a precondition to declaring a unit
to be in commercial operation. However, throughthe mode system and by establishing various
minimum and maximum time limits on the conduct of
preoperational and startup testing, NRC can influence the time schedule for declaring a unit commercial.
Regulatory guides are produced by NRC's Officeof Standards Development and:

Essentially, NRC is saying that power ascension
tests, which are the last of the initial startup tests
and culminate in 100% power tests such as the
100% reactor and turbine trip tests, should bescheduled to be completed no sooner than 3months after fuel load.
The Standard Review Plan (SRP) is prepared forthe guidance of the staff of NRC's Office of Nuclear
Reactor Regulation (NRR) in their review of applications for construction permit and operating licenses.
SRP section 14.2, "Initial Plant Test ProgramsFSAR," was issued on November 24, 1975. Acceptance criteria 11, "Test Program Schedule," contains
l anguage nearly identical to Regulatory Guide 1.68,
stating that at least 9 months be allowed for conducting preoperational testing and at least 3 months
be allowed for conducting startup testing including
fuel loading, low power tests, and power ascension
tests. 281
I nspection and Enforcement Manual

The Inspection and Enforcement Manual contains
guidance for IE inspectors in preparing for and conducting various types of inspections.
ManualChapter 2514, "Light Water Reactor Inspection
Program-Startup Testing Phase," gives the followi ng definition of startup testing: For the purposes ofthis program, startup testing is defined as that testi ng conducted following issuance of the operating
license, starting with initial core loading, but excepti ng incomplete preoperational testing; and continui ng until the plant reaches commercial operating
282
status at or near its licensed power rating."
IE, itseems, recognizes that utilities will normally declarecommercial operation at a point where the unit canoperate at or near its full licensed power rating. The
same Manual chapter also deals with the situation
where a licensee may want to operate at a power
level less than full power without expeditiously completing the remaining power ascension tests at thatand higher power levels. Basically, these criteria do
not allow a licensee to remain at a power level if the
Iicensee has not done all the tests at that level. 283
There is further potential adverse impact in that IE
will require the licensee to perform at the lower
power level tests planned for the next testing plateau so as to demonstrate that the unit can be
operated safely at that lower level over a period oftime. IE will also require the licensee "to obtain NRR
approval for not repeating all planned tests when284
the power level is increased."I n other words, IE apparently thinks it important
to discourage licensees from lagging in performanceof startup testing and recognizes that licensees may
have some motivation to declare commercial opera-[A]re issued to describe and make available to the
public methods acceptable to the NRC staff of implementing specific parts of the Commission's regulations, to delineate techniques used by the staff
in evaluating specific problems on postulated accidents, or to provide guidance to applicants. Regulatory Guides are not substitutes for regulations,and compliance with them is not required. 2 7Regulatory Guide 1.68 deals with the scope anddepth of initial test programs acceptable to the NRC
staff for light-water-cooled reactors. An initial test
program is defined to consist of preoperational (before fuel load) and initial startup tests (after fuelload). 278Startup tests include power ascension
tests.
Specifically, Regulatory Guide 1.68 states:

The power-ascension test phase of the initial test
program should be completed in an orderly and
expeditious manner. Failure to complete the power
ascension test phase within a reasonable period ofti me may indicate inadequacies in the applicant's
operating and maintenance capabilities or may
result from basic design problems.279

After stating that the power ascension phase of
the initial startup testing should be orderly and
expeditious, thus setting an unknown maximum timeframe, the guide goes on to define a minimum timeframe. "Sufficient time should be scheduled to perform orderly and comprehensive testing. The applicants' schedules for conducting the preoperational
and initial startup phases should provide for aminimum of approximately 9 and 3 months, respectively."280221

at each test plateau. The normal operating procedure steps will be blended with the power escalation test program to produce a preplanned, orderly,organized test sequence." 2e9 This suggests thatthe test program will proceed in an orderly manner
through completion and, as previously committed,
commercial operation at full rated power.
This does not imply that GPU should not havemade the commitments in the FSAR nor that NRC
should not have requirements governing the completion of test programs. Rather, the finding of theSpecial Investigation Group is that NRC apparently
has seen a need to regulate not only the depth andscope of startup tests (after fuel load) but also thepace for conducting that portion of the test program.
Furthermore, NRC through the Inspection and Enforcement Manual and through NRR's review of thecommitments in the FSAR, has found it useful tomake expeditious completion of the test program a
precondition to a utility's unilateral commercial
operation decision and to also require that this not
be attempted in less than 3 months.

tion at a time when the unit is operating at less thanfull rated power.
Another Babcock & Wilcox unit, Crystal River 3,
is an example of this commercial operation declaration before completion of startup testing:• Fuel load-December 4, 1976
• Initial criticality-January 14,1977• Commercial operation-March 13,1977• Complete startup tests-April 26,1977

From fuel load to completion of startup tests, 143days elapsed; only 99 days passed from fuel load tocommercial operation.
Final Safety Analysis Reports (FSARs) are submiffed by applicants for operating licenses and arereviewed by NRR. The material in the FSAR is considered a commitment to the NRC, although deviations can occur. IE inspectors can cite a licensee
for failing to meet FSAR commitments.
Chapter 14 of the TMI-2 FSAR describes a test
program divided into three phases: (1) construction,(2) preoperational, and (3) fuel loading and initial
operation. The third phase ends with power escalation tests. According to the FSAR, the third phase"starts with initial fuel loading and ends upon completion of the power escalation program and designationof the unit as ready for commercial opera285
tion."The FSAR is even more specific: "SP
800/21, Unit Startup and Power Escalation Test
Procedure, will be the controlling document for taki ng the unit from a zero power, hot condition
through the various power test plateaus
up to com286
mercial operation at licensed power."

3. ACTIONS TAKEN AT TMI-2 INDICATINGTIME CONSIDERATIONS THAT WERE LINKED
TO FINANCIAL INCENTIVES
Having identified the incentives that existed forthe completion of TMI-2 in 1978, we now examine
the question of whether GPU took any conscious
action to obtain those incentives. Although the evidence is equivocal, we conclude that deliberate action was taken to enable completion of the unit by
the end of 1978 to obtain the previously identified
i ncentives. This conclusion, however, should not beread as the equivalent of stating that this "rush"
compromised the safety of the unit; that question isaddressed in the following section.
As a matter of methodology, there is the difficultyof knowing where to begin looking for a rush tocomplete the plant by the end of 1978. The lifeline ofa nuclear plant can be simply sketched: planning, toconstruction permit, to construction, to operating
li cense, to testing, to operation. At what point do
the incentives for operation dictate a rush in theother phases? It could be argued that a rush inthose phases is always dictated by the desire to get
the unit in operation as soon as possible. But tol ook to the specific date of December 31, 1978 andi magine that GPU rushed the planning phase of
TMI-2 back in the 1960s is difficult. 290 Similarly,
GPU did not begin planning for a December 30,
1978, commercial operation date back in 1969 when

Assessment

I n the FSAR, the licensee (with guidance from the
NRC) makes a commitment to complete the entire
test program before declaring commercial operation.
There was no explicit requirement linking completionof the power ascension test program with commercial operation, as Dieckamp has said. 287 However,Regulatory Guide 1.68 and SRP 9- and 3-month
guidelines were satisfied as illustrated in a test program schedule included in the FSAR. That schedule
shows a period of 11 months before fuel load forpreoperational tests and shows completion of
power ascension tests and estimatedcommercial
288
operation 4 months after fuel load.
The FSAR
also incorporates IE concerns by stating that thepower escalation tests "will be a step by step procedure that either incorporates or references applicable steps in normal approved unit operating procedures required to increase power from one test
plateau to another and maintain steady state power
222

point in time; they were interested in an operating
li cense. 300

291

it received its construction permit to build TMI-2.
In fact, GPU officials did not predict an end of theyear, 1978, commercial
operation date until No292
vember of that year.
Thus, the main focus of attention must be on
events occurring in the latter half of 1978-on
specific action taken when the "cushion" on the earli er predicated date of May 31, 1978 began to evaporate. 293 At the same time, however, the continui ng nature of construction at a nuclear plant must be
kept in mind. Therefore, certain events in the construction of TMI-2 were examined to determine if
there was any indication of a rush even in the pre1978 period. The results of that examination are set
forth to complete the record.

Physical indications of this "push" occurred when
GPU test engineers overextended the unit during
tests. The first of these was a test in which thereactor coolant pump seals were improperly subjected to high temperatures and needed replacement. The NRC inspector on site concluded thatthe pace of the test schedule contributed to the in301
The second incident involved exceeding
cident.
test specifications by failing to wait for a required
302
This incident
resulted in a report of anreaction.
302,303As the inspector
item of noncompliance.
said, "[the test superintendent] basically gambled
and lost in that case.n 304 The inspector added:[I]t's an example, it was one of the first things that
we pointed out to him that we did not care to see
the program run at that pace that you had to takechances, which is basically what he did. 304

The Construction Period

The Special Inquiry Group's interest in the construction period at TMI-2 was piqued by allegations
that GPU may have been interested in rushing constructionof the unit to obtain its operating
294,295
li cense.
As the previous timeline suggested,
an operating license is necessary before power ascension testing and, ultimately, commercial operation. I n turn, because of NRC requirements andpractices, construction must be complete before an
operating license is possible. 29g Thus the argumenti s that GPU could have rushed construction of TMI2 to obtain an operating license earlier, complete
testing earlier, and go commercial earlier. This
scenario is not tied to a December 31, 1978 date.
For that reason, the incentives discussed previously
are probably not 297
involved in any rush to obtain an
operating license.
Some evidence exists that GPU was interested in
obtaining an operating license as early as possible.
Two indications of that are examined: the pace of
preoperational testing and the change of contractors.
"Preoperational" or "hot-functional" tests arethose conducted before fuel loading. By heating
coolant in the primary system with the reactor
coolant pumps (RCPs), steam can be produced sothat components of the system can be tested. This
hot-functional testing is generally well underway before a utility proceeds to fuel loading.
At TMI-2, IE inspectors found that "the [hotfunctional] testing program was being pushed to its"298,299
The project inspector did
absolute limit....
not consider this a rush, because all utilities estaboptimistic schedule" for preoperalish "an extremely
3 0tional tests. o
However, he added:

Many times during the hot-functional testing, theEinspectors
noticed that the test engineers wouldI
have to wait for completion of construction to catch305
up before they could proceed with their testing.
GPU may have tried to solve this problem by replacing the original constructor of the unit.
Technically, "replacement" may be incorrect . 30s
I n June 1977, GPU terminated its contract with United Engineers & Constructors (UE&C) as "construction manager" and hired Catalytic, Inc. (Catalytic), as" maintenance contractor." In the process, GPU assumed the duties of "construction manager." Therefore, Catalytic "replaced" UE&C as the constructor
307
on the site only in rough terms.
GPU's decision to replace UE&C was apparently
not due to any dissatisfaction with that company's
performance as constructor of TMI-2 to thatpoint." ," Rather, GPU was following the system
it had used on TMI-1-and had been used at otherunits 310 -of replacing the constructor with a mainte311
nance contractor as the unit neared completion.
There was sufficient notice given suchthat UE&C
312
was not surprised by GPU's action.
The rationale for replacing a constructor with amaintenance contractor toward the end of construction at a nuclear unit is apparently twofold. First, it
recognizes that on a large project, "construction" isnever complete. There is always additional work to
313
be done to keep the unit in top condition.
Second, it is an admission that worker314,315
productivity
To eldecreases as a job nears completion.
i minate this slack period, a maintenance contractor
comes on board to remotivate craft laborers. 316
I n rough terms, TMI-1 and TMI-2 were in a similar
position when maintenance contractors were hired.
If anything, TMI-2 was less complete when Catalytic

At TMI, I think they were pushing a little harder than
I had seen in other plants in the test program at this22 3

replaced UE&C. 317 GPU officials were, in fact,
surprised that there were so many "open items"
remaining when Catalytic first reported on the statusof the unit. 318
The timing of this change is crucial. GPU replaced its constructor at TMI-2 just as hot319
functional testing began.
Thus, the change was a
method of motivating the construction work, which
was necessary for completing preoperational testi ng. Some of that testing, it will be recalled, is done
before an operating license will be granted.
However, even the substitution of constructors is
not a magic solution for getting work completed. As
the planned date for the operating license approached, GPU found that many items remained
outstanding at TMI-2. 320 In the end, the IE projecti nspector went through that list of open items andspecifically instructed GPU which ones had to becompleted before he would recommend that an
operating license be issued. 321 Otherwise, GPU
would have had to develop its own list of priorities; ali st that might have been incorrect and further set
back the date of the issuance of the license. The IE
project inspector eventually recommended grantingof the license, which the director of NRR did pursuant to an order of the Atomic Safety and Licensi ng Board on February 8, 1978.
As a matter of completeness, any rush in preoperational testing or construction in the late
1977-early 1978 period must be measured against
the entire construction history of the TMI-2 project.
I n the mid-1970s, because of GPU financial probl ems, the construction
schedule at TMI-2 was inten322
tionally staled.
In fact, an audit of this decisionby the Touche Ross accounting firm was used by
the Office of the Consumer Advocate in Pennsylvania and in323
New Jersey to challenge the total costof the unit.
UE&C's project manager of construction at TMI-2 confirmed that budget restrictions
were imposed on his management
324 of the project
during the 1974-1977 time period.
I n perspective, therefore, if there was a need torush construction and testing in 1977 to obtain theoperating license and proceed with completion of
the unit, it may have been due to a previous slowdown in the project. If this fluctuation was causedby financial pressures on GPU, it is325
something of
which the NRC should be concerned.
Assuming GPU did rush to obtain the operating
li cense for TMI-2, both by pressing the hotfunctional testing schedule and by motivating increased construction through a change in constructors, what is the impact on the analysis? As statedat the outset of this section, obtaining the operating
li cense on February 8, 1978 does not appear linked

to the incentives that flow from a December 30,
1978, declaration of commercial operation. Rather,a desire to obtain an operating license and proceedwith power ascension testing indicates only thegeneral desire to complete a unit as soon as possible. GPU was not alone in desiring that326
result.
I n fact, a Babcock & Wilcox (B&W)
employeestated that industrywide
utilitiesrush
toget their
327,328
This, according to theoperating licenses.
employee, results
327 in added complications in completing the unit.
I n conclusion, even assuming GPU rushed to obtain its operating license, nothing indicates that suchaction was tied to a commercial operation date ofDecember 1978. The prelicense phase, therefore,
reveals no rush to obtain the incentives identified.
However, the action taken by GPU 329
to obtain its
operating license in February 1978
foreshadowed the resources the company could mobilize toobtain a desired goal: intense test schedules andcontractor pressure. Both of these will become important in our analysis of the postlicense period.
Post-Operating License Period

It was not until GPU realized there was a possibility that TMI-2 would not be commercial in 1978 thata rush to obtain the incentives connected with thatdate was possible. Not to minimize the possibility
that there is a general rush to completion of a nuclear unit,
or a rush for some other incentives,
the focus of this investigation has been the rush toobtain those financial advantages associated with a
December 1978 completion date.
The starting assumption made here is that up until the main steam relief valve failure of April 23,
not concerned with a December
1978, GPU was332
It was probably only after the
1978 deadline.
April 23 transient that the potential for missing that
Therefore, the madate first occurred to GPU.
j ority of our analysis is devoted to two events occurring in this period. If there was a rush to obtain
the incentives, it would have to have occurred in this
8-month period .
Specifically, we examine (1) the power ascension
test schedule and (2) the replacement of the main
steam relief valves as situations in which conscious
action might have been necessary to bring the unit
i nto commercial operation before the end of theyear.
The power ascension schedule had been335
setting forth the steps
transmitted to PaPUC
necessary before GPU would declare the unit incommerical operation . Thus, by its own action,
GPU had placed the test schedule on the "critical
224

337

path."
Late in 1978, there was also some reason
to believe that the IRS would not consider TMI-2
placed in service if the power ascension tests were
not completed in 1978 .
The main steam relief valve failure of April 23,
1978, similarly created problems on the "critical
path." Despite numerous small problems, before
that failure there apparently was little doubt that
TMI-2 would havebeen in commercial operation by339,340the end of 1978.
With the discovery that thevalves had malfunctioned, however, GPU had to decide quickly what action to take. Without the main
steam valves, power ascension testing (and commercial operation) could not begin.
Power Ascension Test Schedule

By way of background, the power ascension test
schedule that a utility eventually performs at a nuclear unit is a product of many different sources.
The NRC requires that a startup test program be
conducted. 341 The NRC further suggests the typeof tests that should
be included in the power ascen342
sion program.
Beyond this, a utility is free to impose additional tests upon itself. Some of these aresuggested by the nuclear steam system supplier,based upon previous experience at other units. 343
There may also be tests the utility desires to gather
data or improve the reliability of a unit. By our definition, the power ascension test schedule is composed of all of these planned tests, as recorded in
the unit's master test index.
A lengthy list of tests is also included in chapter
14 of the NRC-required FSAR. While only safetyrelated tests must be specified in the FSAR,344 utilities sometime include other scheduled tests. Recalli ng that the FSAR is filed before an operating
license is issued, this requires some long range
planning on the part of the utility.
Some other tests are not included in the FSAR.
They may show up on the master test index corporate test diagrams or internal memoranda butnever be subject to official scrutiny. For example,of the 170 tests initially scheduled in the entire program at TMI-2 (preoperation and power ascension),
only approximately 85 were safety related and required by the NRC. 345 In fact, the FSAR for TMI-2
li sts 88 tests . Some additional tests were addedby the vendor, others by the utility itself. Yet eventests not listed in the FSAR (not required for safety)
must be considered relevant in the investigation of arush. If GPU thought it worth including a test in its
planned sequence in 1976, it presumably would
have the same opinion of the test in 1978.
In the October 26, 1978, meeting of the Commer225

cial Operation Review Board (CORB) at Three MileI sland, 7 it was announced that "[seven] tests will
not be completed as originally written since anevaluation determined that there are no unresolved
problems and none of the testing omitted is related
to Federal, State or local requirements." W
According to the TMI-2 test superintendent," There were seven test procedures at that time [ofthe CORB meeting] that we had not committed to in
the FSAR, that we had not performed and theseprocedures were developed by us and only requiredby us." 349 As examples, the test superintendent
li sted the following:

We had a pretreatment plant that would makedrinking water on Unit Number 2. We also had one
in Unit Number I that supplied all the water weneeded. Therefore, we never did get that system inservice. We had a demineralizer that would makedemineralized water to fill the condensate system.
[The make-up demineralizer discussed in this list is
to be distinguished from the full-flow condensate
polishers (i.e., demineralizers) that have been associated with the initiation of the March 28, 1979 accident.] The unit one system was quite large andsupplied all our needs. When we loaded fuel, we
had testing to do on the fuel handling equipmentthat we had some parts [missing?] that we did notcomplete at the time.... When we received theparts they would be completed later on. We had asampling system that would sample water in a condenser.... There are other methods to locate it
but it's harder. That's the type testing that was inthere [the seven tests)

The TMI project manager said a review of possible deletions was ongoing. "We looked all the timeat things that may be in our program that weren't
necessary," he said. 351 "If they aren't necessary
and they don't provide you something tangible forthe operation and the safety of the unit andyou can352
delay it or defer it or not do it, why not?"In fact, GPU deleted a totalof eight tests from its
353
original master test index.
GPU, therefore, performed approximately 160 startup tests. Half of
those were not required by the NRC.
Posed against these GPU explanations of thereason for deleting the tests must be considered thefollowing: The power ascension program at TMI-2
354
was completed on December 28, 1978.
I mmediately following the completion, power escalation began, which resulted in declaring the unit in commer354
cial operation on December 30, 1978, at 11 p.m.
What if GPU had followed its original sequence, performing all seven deleted tests, would it have beenpossible to meet a December 30, 1978 commercial
operation date?
If it would not have been possible to complete thetest program before December 31, with the sevenwas a formality in our case because the warranted
output related to about 87 percent power andclearly we had the energy output equivalent to 87
percent power. So there was no incentive from mystandpoint to perform that test before the end of
the period that the contract provided for.... 366,367

tests, then their deletion assisted GPU in obtaining
the previously identified financiafincentives, by enabling it to declare the unit commercial in 1978.
The explanation of the deletion as necessary for
operation is the weaker of the two explanations.
The decision to delete the tests must have been
made before October 1978. At that time, GPU officials have insisted that they were355
not concernedwith a December 1978 deadline.
Although it
could be argued that recent events would havecounseled against being too optimistic, 356 no evidence suggests that the tests were ordered deleted
specifically because of time considerations.
I n addition, GPU performed a vast number ofvoluntary tests. To have provided an even more
comfortable cushion on "commercial operation," it
could be expected that other tests would have been
deleted. We know of none other than those previously mentioned.
Thus, the explanation for deleting seven tests, asoffered by GPU officials, seems plausible: experience with TMI-1-and the unexpected capacity ofthat unit to carry TMI-2 as well-made some test
procedures
drafted before TMI-1 went into opera357
tion
obsolete and redundant.
A second change in the power ascension test
schedule is more358
difficult to understand, however.
Both
the
FSAR
and GPU internal memoran359,360
dali st the "unit acceptance test" as one thatwas scheduled to be performed
before declaration361
of commercial operation.
Inclusion of the unit acceptance test in the FSAR is somewhat odd. The
test, according to an abstract, is designed to "verify
that the energy output from the nuclear steam supply system meets or exceeds the (Nuclear SteamSupplySystem) NSSS contract warranty out362
put."
Such a test would seem to be related more
363,364
to contract requirements than safety.
I n fact,
the unit acceptance test is one365of the tests in standard B&W FSAR chapter 14.
Thus, it can bepresumed B&W suggested to GPU that the test be
i ncluded, and GPU apparently agreed.
The unit acceptance test of TMI-2 was not run
before the declaration of commercial
operation. It
366
was run in February 1979.
The explanation forthis postponement from GPU officials was that itwas not necessary to run the test before commercial operation. The GPU vice president of generation said that, although the test was "important froma contractual standpoint," it "was not a total overall366
measurement of performance of all systems."
He added:

The GPUSC project manager at TMI, whose job
description made him responsible until368"satisfactorycompletion of the initial warranty run,"said there
was no need to run the test before commercial
operation. Calling the test "an academic exercise,"
the project manager said that data on steam output
had already been taken in two earlier runs on TMI2.369 He also said that output of TMI-1 indicated tothem that there was370
a "certainty of getting a similar
output ... for Unit 2."
Again, the explanations of GPU officials must becompared against the other possibility; that postponement of the unit acceptance test enabled GPU
to declare the unit commercial in 1978, when thatwould not have been possible otherwise. It has
been stated that a unit acceptancetest is generally371
run after commercial operation.
The utility wants to be sure that the unit operates
as warranted by the vendor. This is best demonstrated by substantial
generation at full power over372
a period of time.
However, GPU clearly stated its intention to per373
form the test before commercial operation.
Leaving aside the 374
confused legality of altering an
FSAR-stated test,
and the equally confusedstatus of GPU's "communication" to PaPUC that thetest would be performed before commercial opera375,376
GPU's reasoning for postponing the testtion
is questionable. Why would the performance of one
unit (TMI-1) ipso facto provide assurance of theother's ability? If there was no logical reason for
performing the unit acceptance test before commercial operation, why was it so listed in the FSAR?
Recognizing the large amount of full power
operation necessary to do the warranty run, 377
postponement until after commercial operation allowed GPU to meet a December 1978 deadline thatapparently would have been otherwise impossible.
The postponement, therefore, is indicative of conscious action taken to obtain the previously discussed incentives. However, assuming the unit acceptance test is important only for contractual purposes, there is no reason for its inclusion before
commercial operation. Thus, GPU could at most befaulted for imposing more stringent standards on itself than it ultimately could meet. The point here
goes not to the propriety of the postponement decision, but to the very fact such a decision was apparently "required."

I know I was not interested in formally performingthat test prior to the end of the period in which I
was permitted under the contract to perform it. It
226fective valves have delayed and are continuing todelay the commercial operation of TMI-2, causing
the owners excessive costs and their customers
higher rates.='382

Replacement of the Main Steam Relief Valves

On April 23, 1978, TMI-2 was operating at 28%
power during the conduct of that part of the test
program known as the "15-40 percent power escal ation phase." The reactor tripped leading to an increase in pressure in both the reactor plant andsteam plant. Normally, this pressure increase iscontrolled by main steam safety relief valves
designed to open at preset pressure levels. (Thesevalves should be distinguished from the power
operated relief valve (PORV) which stuck open andhas been identified as a contributor to the March
28, 1979 accident.)
The steam relief valves did open and vent the

The full history of the extent of testing the valves
and the various adjustments attempted may comeout in court as a result of legal actions now underway 'between the valve manufacturer and GPU. A
condensed history is contained in the Holcombe August 18, 1978 letter to FERC. What is important relative to the rush to commercial operation issue iswhether the decisionmaking process on what to doabout the problem was rushed and whether the actions to carry out that decision were unduly rushed.
, 1978. The first
ThetransiocudApl23,theamosrnApil23;hwev,
meeting with the valve manufacturer occurred May
23, 1978. Within a few days after the April 23 transient, however, GPU acted to create an alternative
to repor adjustment of the existing relief
valves.
GPUSC personnel began to canvass
valve suppliers to identify replacement valves. The
only valves found that were the same size as thedefective valves would not be available until the endof November 1979.
Smaller valves were immediately available from another utility and were similar
to those used in TMI-1.
Burns & Roe, thearchitect-engineer, was directed to start engineeri ng work on design modifications that would beneeded if the existing valves were to be replacedwith the smaller valves.
The answer to the first question, whether the decisionmaking process was rushed, is yes. A decision was made almost immediately after the April 23
incident to create an alternate course of action.
Valves were located, and design changes were ordered. In answering a question about these contingency preparations, Robert Arnold said, "Wewent further than that. We ordered materials and
we ordered valves, recognizing that maybe wewould fix the problem ... and have to salvage thatmaterial."385 (That is, sell or scrap the newly ordered material).
Part of this contingency planning was establishi ng a critical path network that would allow one todetermine how long testing could continue on theexisting valves before this testing would add extra
days to the time needed to perform the replacement
work. To quote Arnold again:

the valves did not close as they were supposed toas the pressure returned to a normal range. As aresult of the main steam safety relief valves failing toclose appropriately, excessive heat was removed
from the main steam system. This caused thesteam generators to cool down, thereby causing thereactor coolant system to cool down excessively.
The rapid cooldown of the reactor coolant system,and the associated decrease in reactor coolant
pressure caused the emergency core cooling systern to operate "in a manner similar to that expectedduring a loss of coolant accident." 378 This "excessive blowdown" was caused by the valves not reclosing and it was thought initially to be merely aproblem of "adjusting the reclosure pressure."379
Apparently, however, reclosure pressure adjustments alone were not able to solve the problem: "Itbecame apparent about May 20th that the allowableadjustments were not correcting the reclosure
problem with the main steam safety [relief]valves."379
Significance of This Event

Thus GPU, in a shutdown mode for almost 1
month, clearly had foregone the planned May 31,
1978, commercial operation date. If December 31,
1978, was ever a critical deadline, it would seemthat even that yet far off date was now challenged.
If there was a rush to year-end commercial operation, it had to begin with resolving the main steam
relief valve problem. 380
GPU clearly had its sights set on commercial
operation because in a letter to the valve manufacturer in late June, it said:

Effectively, we stayed [with the old valves] until wewere at the point where we had to make a decision
whether or not to make the change out if we wereto avoid additional delay in the event we had to gothat direction eventually. Up until the time that thecontinued testing of the ... valves would not extend
our schedule, we stayed with them." 388

Since more than two months have elapsed following the discovery of the problem and the trial ofvarious unsuccessful solutions of the problem, it isour opinion that these valves cannot be corrected
to meet our requirements. As you know, these de227

As to whether the actions to carry out the replacement decision were rushed, modification work387
was initiated June 23, 1978and completed on
August 24, 1978. Several days after August 24
were needed for testing the new valves, cleaning up
the feedwater, and returning to power. The turbine
generator was synchronized with the grid on September 18, 1978, and power ascension testing
resumed. The fact that only 2 months elapsed fromthe April 23 incident until GPU was ready toproceed with modifications meant that preparations
had to be carried out expeditiously. Donald R.
Haverkamp, TMI-2 project inspector, stated: "I never heard any discussions to [the] effect"that there389
was a rush to get the valves replaced.
He also stated that IE was aware (through the
Licensee Event Report) of the situation and in fact
was notified by GPU
390before any work began on replacing the valves.
Yet he also expected a rush
to replace the valves. "I would certainly expect that
there would be a rush to get them replaced-that is,
that
they
would
expeditethereplacement... because ... they couldn't continue
with the startup program until they replaced thevalves. "390

Other Indicia of Time Concern

I n addition to the deletion or postponement of
tests and the decisionmaking with respect to themain steam relief valve replacement, we havel ooked at other events at TMI-2 during the latterpart of 1978 that could also be indicative of a desireon the part of GPU management to complete theunit before the end of the year, 1978. Some ofthese are minor; all are only circumstantial evidenceof a rush.
As previously discussed, the decision to declarea unit in commercial operation is the utility's. The
vagueness regarding the criteria for that declaration
flows, in part, from the different standards used byutilities. Recognizing the regulatory
impact 392 and393
risk involved in this decision,
Herman Dieckamp,
President of GPU, instructed that the decisionmaki ng on
declaring a unit commercial be formal394,395
i zed
Shortly after becoming
President,
396
Dieckamp instructed an assistantto prepare
GPUSC criteria for placing a unit in commercial
operation. 397 It was firstused in a review of GPU's
398
coal unit, Homer City 3.
By the time TMI-2 was ready to be considered
for commercial operation, it was simply a matter ofapplying the GPUSC criteria against the physicalstatus of the399
unit. A meeting of the GPU organization (CORB)
that was to make the determinationof readiness for commercial operation was held atThree Mile Island on October 26, 1978. At thatmeeting, vice presidents and other employees of
GPUSC and the operating companies listened topresentations on the status of TMI-2 vis-a-vis thecriteria previously established for commercial operation.401
By the end of the day, it was clear that some major matters remained to be completed before themembers would be satisfied with the unit's readiness. The seven CORB members then appointed a
subcommitteeof four to follow up on those402
items,
with the understanding that the subcommittee would sign off when those remaining items
had been completed. 403 The full CORB concluded:

Assessment

GPU wrote to FERC explaining the valve problem,
stating: "Completion of the main steam safety valve
modification in August will permit a return to powerin mid-September, a delay of about one hundred
387
forty (140) days in the project."
An analysis Arnold requested of test delays reported in January
1979 stated that "because of problems encounteredi n the Test Program other than the safety valve
failure, the safety valve problem itself was solely
responsible 388
for a period of delay on the order of 20
to 39 days."
To not replace the valves with those of a different
design meant a delay until the early part of November 1979, when similar-sized valves might havebeen ready from the manufacturer or whenever the
existing valves would be fixed.
The early establishing of an alternate course ofaction and the use of critical path planning cannot
be faulted. IE inspectors did some limited testing 391
orobservations of welds on the modification workand this turned up no indication of a rush. Therefore, our finding is that the replacement was notrushed but done in an orderly, expedited fashioncommensurate with the circumstances of having anearly complete unit and hundreds of personnel
otherwise kept waiting for resolution of the valve
problem.

Based upon the consideration of the information
furnished and discussion of that information, it isconcluded that the status of Three Mile Island Unit
2 with respect to all criteria in the (GPUSC Manual
Chapter) Procedure is acceptable. Therefore it isdetermined that the Unit is technically ready forcommercial operation and the Operating Company(Met-Ed) is prepared to support commercial operation at a power level of 880 MWe ....
This statement was made on October 26, 1978,even though a number of items remained outstandi ng. 405 For example, 250 to 300 "deficiencies" re22 8quiring physical construction remained to be
4o6,407
cured.
Nonetheless, the subcommittee, consisting of Arnold, Herbein, Hirst, and Wilson, was passed the ulti mate responsibility for seeing that the conditions
subsequent to the full CORB's signoff would be fulfilled . In addition to those four officials, TMI-2
Station Manager Gary P. Miller was to "review" thesubcommittee decision, justas he had reviewed the
4o9
initial CORB's conclusions.
It should also be noted that, organizationally, Hirst 410 and Wilson reported to Arnold.
411
The CORB subcommittee held no meetings,
but its members said they kept track of the progress of outstanding items for which they were
responsible. 411 On December 29, 1978, 1 day after
successful
completion of the power ascension pro412
gram,
the CORB subcommittee members signed
off on a report, which concluded:
It is the opinion of the Subcommittee that the Unit
(TMI-2) has demonstrated its ability to operatesafely and reliably up to and including 959 MW
gross and should be placed into commerical service.... 13 (Emphasis added.)

It i s perhaps somewhat inaccurate to state thatmembers of the CORB subcommittee "signed-off"on their report on December 29, 1978. For, in fact,
only those members working at corporate headquarters(Parsippany, N.J.) physically signed their414
names.
Arnoldsigned "per telecon" for both
414
Herbein and Miller.
The explanation for this signing "per telecon" islogical. Arnold said that he telecopied a copy of the415
subcommittee report to both Herbein and Miller.
"Since I was in Parsippany or Mountain Lakes, Herbein was in Reading and Miller was at the site," hesaid, "it was not felt necessary on my part to send a
messenger on a round-trip
to get the signatures415
from them personally."
Mr. Herbein has testified
that he had "no problem" with the telecon procedureand "agreed it was certainly appropriate." 416
There is no suggestion that Arnold improperly
signed off for either Miller or Herbein. In fact, thevery existence of a CORB is not required by the
NRC 417 Furthermore, Arnold had the responsibility
for declaring TMI-2 in commercial operation. 418 It,
therefore, was consistent with his responsibilities
that he would oversee the CORB subcommittee
report-even if that required consulting with othermembers via telecopier and telephone.
However, the very fact that Arnold felt the needto complete this approval process before the end of
the year is an additional indication that GPU wasconcerned with the timing of the commercial inservice date of TMI-2. The signing of a signature "pertelecon" is, in itself, insignificant. But the attitude
and pressure that it reflects is of interest.
Under such circumstances, it could be argued,
the pressure of a superior asking for approval fromhis employees is not conducive to frank dissent. On
the other hand, there is no indication in the TMI-2
case that Arnold's method improperly influenced
any other member of the CORB subcommittee. As
Dieckamp foresaw when he proposed the establishment of commercial operation criteria, the operatingcompany personnel would not accept419
a unit thatwas not ready for commercial operation.
I n sum, while the signing "per telecon" of the
CORB subcommittee report 2 days before the endof 1978 does not look li ke good procedure in retrospect, it probably was an exercise of good businessjudgment. There probably would have been no
difference had Arnold convened a late-night meetingon December 30,1978.
However, the episode remains indicative of thefact that GPU officials were aware of the importanceof completing the commercial operation
process be420
fore the end of the year, 1978.
Why else would
Arnold take the trouble of contacting officials by
telephone on December 29, 1978? If December
were not an important deadline, why not simply mailthe CORB subcommittee report to the distantmembers? This statement is made in full recognition of the fact that there was no regulatory significance to the CORB subcommittee approval. Thereapparently was, however, a desire to carry out thecorporate procedure for that decision consistent
with the December 31, 1978, date, which was important for other purposes. 421,422
Aggressive Power Ascension Test Schedule

I n addition to the CORB procedure, there wereseveral other indications of time concern that we investigated. One of these-the pace of the power
ascension test program-was prompted by worker
423
comments that the pace had
424 been demanding.
As previously discussed,
the power ascension
test program was on the critical path to commercial
425
operation. Because of various representations,
GPU could have come to the conclusion that thetest program would have to be completed
in 1978 to
426
obtain rate treatment and tax incentives.
Because of the main steam relief valve problem,GPUSC employees did not begin the power ascension test program until September 19, 1978. They
completed the427
power ascension test sequence, by
their definition,
on December 28, 1978. In those
2 1/2 months of testing, GPU completed testing thathad 428
been originally slated to take exactly that
long.
229

The relationship between GPUSC and Met Ed
employees in completing the power ascension tests
should be understood. GPUSC test engineers were
responsible for running the tests and preparing theplant for commercial operation. 429-431 However, because there was nuclear fuel in the core, only
NRC-licensed operators could manipulate
the con432
trols necessary to perform the tests.
I n informal
conversations, we heard reports of conflicts
between Met Ed employees and GPUSC test engineers over the pace of the test schedule. Herbein
admitted that such a "conflict"
was possible but
433
dismissed it as "healthy".
Such pressure, however, is indicative of the pace of the test sequence
itself.
The IE inspector at TMI-2 at the time of thepower ascension testing observed:

I would say that the power ascension testing was
conducted in a manner to complete it as soon as
they could-that is, people were working overtimeor additional hours because it was necessary to do
more work each day than you could normally perform in an eight-hour day. I think it was a very aggressive pace. 434

444

and commercial operation was typical.
Assuming
those plants also completed their power ascension
test 445
program before declaring commercial operation,
GPU would again appear to be within average time limits. Initial criticality occurred at TMI-2
on March 28, 1978, and commercial operation was
declared 9 months later on December 30,1978 446
Allowing 3 months for main steam valve replacement would give TMI-2 a 6-month period, exactly
the average.
I n sum, if the unusual downtime caused by themain steam relief valve is taken into account, thepower ascension test schedule at TMI-2 was not
unusually short. If anything, it was slightly longer
447
than the average.
Even assuming the pace tohave been aggressive, it was apparently not unusually so, when measured against industry performance records. 448
Discontent Among Workers Regarding Quality ofWork

I n a related matter, our investigation touched on areport in the Philadelphia Inquirer that quoted former
Met Ed and GPU sources as suggesting that tests
at TMI-2 had been "faked" or skipped entirely. 449
Workers were quoted as saying, 11 . .. unit two wasrushed.
Everybody who works there knowsthat." 449
The majority of named workers in that article
were contacted. However, many of the more serious statements came from unnamed sources. Because the newspaper would not reveal thosesources and this Special Inquiry Group had limited
ti me and resources, not all allegations were investigated. The picture that emerges, however, does
not450,451
support the broad allegations in the article.452
Specifically, there was no one on the record
who
was aware of tests being "faked" or "skipped." This453
as well as GPU and Met
includes NRC officials454
Ed employees.
Apparently, the worker discontent expressed in
the newspaper article, as with the allegations thatthe pace of the power ascension test program wasdemanding, is more in the nature of typical worker
gripes, than serious safety allegations. In themselves they may indicate some pressure to push
the completion of the unit, but we cannot assess
how those pressures weredifferent from pressures455
on other large projects.

GPU officials agree, calling the test schedule an
However, both NRC officials"optimistic one." 4and GPU employees have stated that it is the natureof the test program and the job of the test superinan"aggressive"
tendent 436,437
toestablishschedule.
I n fact, the test superintendent incharge at TMI-2 said that he would have been evenmore "aggressive" if he had not been forced to wait
for construction to catch up with the scheduled
test.4
A comparison with other power ascension test test
periods does not indicate the TMI-2 program to beunusually short. An analysis prepared by the B&W
manager of plant startup services
showed a"B&W planned start-up schedule" to run
5 months
440
from fuel load to unit acceptance test. 441 On thebasis of experience with eight B&W units,
however, B&W found that that period could range anywhere from several months to 20 months.44o
The time from fuel load
to unit acceptance test
442
The power
ascension
took 12 months at TMI-2.
443
as defined by GPU,
took 10test program,442
If there was not the 3-month delay
months.
caused by replacement of the main steam valves, a7-month power ascension schedule at TMI-2 would
certainly have been reasonable, when comparedwith other units. It would, in fact, be longer than the"planned startup schedule."
Another independent analysis of 62 operating
plants in the United States demonstrated that aperiod of approximately 6 months between initial
criticality (necessary for power ascension testing)

Nexus Between Incentives and Action Taken

We have stated in this report that GPU took
specific steps to enable a declaration that TMI-2
230

was in commercial operation by the end of December 1978. We have further stated this action
was for the purpose of obtaining the previously
i dentified
incentives, which were linked to that
56
date.
However, this is an inference. It might beargued that these are separate phenomena; whatever deliberate action was taken to complete TMI-2
i n 1978 was taken for reasons other than the financial incentives. 457
However, our investigation suggests that the circumstances connecting these two items is credible
enough to draw the nexus. Specifically, GPU
operating officials, and through them, other personnel at the site, were explicitly informed of the financial benefits associated with completion of work at
the site before the end of the year. Despite explicit
i nstructions not to rush to obtain those incentives,operating people were arguably indoctrinated withthe financial goals of GPU. Thus, we have inferredthat the actions we have described were the resultof a desire on the part of management to obtain thepreviously described incentives.
458
As stated previously,
Robert Arnold attended
the December
1978
meetingof the GPUSC Board of459
Directors.
I n the course of that meeting, GPUSC
Comptroller Edward Holcombe testified that heshowed Arnold Revenue Ruling 76-428 because "I
wanted Mr. Arnold to be aware of what the revenue
regulations said, to get his interpretation of the physical characteristics of the construction of the plant
as to whether they met those." 460 I n other words,
Holcombe was attempting to get Arnold's assessment of the status of the TMI-2 construction andtesting vis-a-vis the unit described in the revenue
ruling.
But exactly why it was necessary to provide Arnold physically with the revenue ruling has not been
explained. Holcombe had access to monthly reports describing the progress of construction at
461
TMI-2.
Although Revenue Ruling 76-428 involves some engineering judgment, its interpretation
apparently is more a matter for legal and financial
experts rather than GPO's top operations (generation) official.
Arnold is not sure he reviewed the revenue rul462
He recalls receiving a memorandumi ng.
describing GPU's position
on obtaining tax benefits463
The only such memorandum
for TMI-2 in 1978.
we know of is that prepared by Daley of the GPU
tax department. Holcombe insists that
Arnold did464
not receive a copy of the Daley memo.
However, no one disagrees that Arnold was
asked a number of questions at the December 17,
1978, GPUSC Board meeting with regard to thestatus of TMI-2, 465
as measured against explicitly deThere is little doubt that a disfined tax criteria.

cussion took place, either
before all members of the466
i n which Arnold was intiboard or at a sidebar,
mately acquainted with the tax consequences ofcompleting TMI-2 in 1978. It was his opinion at that
December meeting that TMI-2 had, in fact, met
the467,468
criteria set forth in Revenue Ruling 76-428.
Whether Arnold picked up on the caveat in Revenue
469
Ruling 76-428 regarding problem-free operation
is not known, but he did make reference to the main
steam valve
problem in assessing the unit's tax ac47o
ceptability.
Arnold was also heavily involved in the rate
proceedings that were pending as TMI-2 neared
completion in 1978. He was aware of the calendar
1978 test year in the Penelec proceeding and thepotential for technical arguments should TMI-2 go
471
i nto commercial operation outside that test year.
He also prepared Met Ed's version of the Memorandum of Law requested by the administrative law
judge in that proceeding
472dealing with the issue of"commercial operation."
Thus, it could be said that Arnold, the chief
operations official of GPU, was well informed of thetwo major incentives previously identified: rate
recognition and TMI-2 tax benefits. As the person
directly responsible forallowing TMI-2 to go into
473
commercial operation,
he knew the "costs" of a
failure to do so by December 31,1978.
However, Arnold did not share this burden alone.
Many GPU and Met Ed employees, of both senior
and relatively minor stature, knew that there were
corporate advantages to declaring TMI-2 commercial before the end of 1978. For example, Arnold
discussed "the posture of being commercial vis-avis the rate case and not
being commercial" in his474monthly staff meetings.
John Herbein, Met Ed's
Vice President for Generation, recalled that he "Discussed [commercial operation]... a number of times
between myself and Walt 475
Crietz [former Met Ed
President] with Bob Arnold."
Even in lower levels of plant operations,engineers-in-training,
control room operators, and476
other employees
knew that there were financial
advantages to GPU in declaring TMI-2 commercial
i n 1978.
Even contractors, such as Burns &477,478
and Catalytic, Inc., 479 knew "that it wasRoei mportant to GPU ... for accounting reasons, if forno other reason, to try to get the 480
plant on-line commercially before the end of 1978."With such knowledge disseminated throughout
the plant, it is logical to draw a nexus between theaction taken to complete the unit (as previously
identified) and the known incentives. GPU officials
dispute this by pointing out that top management
explicitly instructed that there be no rush. GPU
President Herman Dieckamp and Chairman of the231

Board William Kuhns contacted Robert Arnold latei n December, "when completion of the test program(in 1978) was problematic. " 481 Their message, according to Arnold, was "...that I was not under any
pressure to declare the test program complete or totake the approachof declaring it commercial at482
some partial load.
Dieckamp remembers telling
Arnold " ... that the staff was not to depart from therequirements of the test program ... they were not
to depart from doing things in accordance with theirown judgment483
for the simple purpose of achieving
the schedule."
Arnold apparently passed these instructions
along to certain senior officials.
I n turn, Arnold
i nstructed that, unlike past holidays, there would be
no extra manning over Christmas 1978. 5 Arnold
said the action "grew out of a concern on my partas to whether it would be prudent to put that kind ofpressure on them [the workers at the site] .
When asked why he felt it was necessary to givethe "do not rush" instruction that he did, Dieckamp
said it was important that Arnold "understood therelative importance of conducting the program safel y in relationship to the schedule. ...I felt it important to make sure he [Arnold] didn't imply somepressure that I didn't want to convey." 487
The effectiveness of these "do not rush" messages is difficult to measure. In some ways, saying"do not rush" in late December 1978, after previousl y instructing the same officer in the ramifications of
not completing the unit in 1978, is similar to the "donot fix prices" advice given in the late 1950s to themarketing
employees in the electric industry investi486,489
gation.
Arnold said some employees did, in fact, workover Christmas. He attributed this to a "sense490
ofpride," rather than any corporate pressure.
Those distinctions may be difficult to make when
dealing with ambitious engineers and employees
looking at long term careers. Although GPU officials
explicitly attempted to balance the pressures thatwere building toward a rush to completion, they may
not have succeeded entirely. Our conclusion is thatsome action was taken to enable completion of
TMI-2 by the end of 1978. The nexus between action and the financial incentive previously discussed
i s provided by the intentional communication of thei mportance of those incentives to the operating personnel responsible for completion of TMI-2. 491
Assessment

I n this section we examine the construction
period (rush to operating license), deletion of seven
self-imposed tests from the power ascension sequence, postponement of the initial warranty run, re-232

placement of the main steam relief valves on a critical path, and other minor indications of time pressures. Although each issue deserves separate
treatment and qualification, the cumulative impactin our minds-is to substantiate the conclusion thatthese actions were taken to enable completion of
TMI-2 by the end of 1978. But before proceeding toan analysis of the safety impact of the action taken
at TMI-2 to enable commercial operation in 1978,
we should pause to assess the nature of these actions.
Many of the actions which we have spotlighted
as indications of deliberate action to complete theunit were self-imposed standards of GPU. Desiring
to go beyond NRC requirements, GPU establishedmore sophisticated test sequences,
commercial
492
operation criteria,
and
the
like.
Becauseof time493
constraints,
as the end of 1978 approached,
GPU chose to relieve itself of the requirements thatit had earlier imposed. Thus, when we examine thisaction as taken to enable completion of TMI-2 by acertain date, we are not suggesting that GPU violated any regulatory requirements. We are simply
recognizing these factual changes as indications ofa time concern.
Several considerations should be balanced
against our conclusions. First, there are the explicit
statements of the GPU personnel offering alternate
explanations for the actions on which we havefocused. Second, no evidence suggests that an explicit order to complete TMI-2 by the end of 1978 to
obtain financial advantages existed. Third, the practice in the industry should also be considered. In
practice, a rush to complete a unit
494as soon as possible may be extremely common.
This would enable a utility to generate (presumably)
surplus power
495
that it could sell to other utilities.
Many of theactions taken by GPU, in fact, might be seen as
above average when compared with industry practice. Critical path planning, a CORB, and advanced
test sequences may be indicative of superior utility
management; not dereliction of responsibility.
Finally, the entire environment in which decisions
regarding TMI-2 were made must be understood.
GPU and other utilities do not operate in a vacuum,
but in a highly regulated system. The effect of thatsystem must be factored into any allegations of a"rush to commercial operation."
4. IT CANNOT BE CONCLUDED THAT THE
ACTION TAKEN TO ENABLE COMPLETION OF
TMI-2 IN 1978 COMPROMISED THE SAFETY OF
THE UNITAs emphasized in the introduction to this re496
port,
the ultimate question in this investigation iswhether the safety of TMI-2 was compromised by
the alleged rush to commercial operation. Having
497
i dentified that there were incentives to rush,
andthat deliberate action
was
taken
at
TMI-2
to
obtain498
those incentives,
we now reach that ultimate
question.
I n our analysis below we conclude that it is notpossible to say that the rush to commercial operation that we have identified affected the safety of
TMI-2. At the same time, however, we believe there
i s a needto address the implications of our investi499
gation.

Therefore, NRC reviews applications submitted byapplicants as measured against defined criteria .
In its most basic terms, if a license to operate a unit
is issued, the NRC believes it to be "safe."
Following issuance of a construction permit or an
operating license, however, NRC regulations maintain control over a licensee by providing:
A license or construction permit may be revoked,
suspended or modified ... for failure to construct
or operate a facility in accordance with terms of theconstruction permit or license ... or failure to observe, any of the terms and provisions of the act,
regulations, license, permit, or order of the Commission. 507

Association with the Accident

In assessing the impact of the alleged rush tocommercial operation, our investigation looked
beyond the March 28, 1979, accident. That is, wewere interested in learning if the overall safety of
TMI-2 had been compromised in some fashion, suchthat another hypothetical accident might have occurred.
For the sake of clarity, however, it should be noted that nowhere in our investigation did we uncover
any connection between the action taken by GPU toobtain the 1978 incentives and the March 28 accident. There was no rush of which we are aware
i n any procedures, practices, or equipment that has
been identified as contributing to the accident atThree Mile Island on March 28,1979. 5m When we,
therefore, discuss the possible "compromising ofsafety" at TMI-2, we are not suggesting that the
specific March 28 accident
was caused by the rush501
we have investigated.

With this authority, the NRC Office of Inspection and
Enforcement monitors the construction and operation of a nuclear unit. If IE determines that a unit is
not being constructed in conformance with NRC regulations (which, as previously noted, define what issafe), it presumably takes enforcement action. Thisaction could be citing the license with a notice of508
violation,or in serious
instances, halting con9
struction or operation
The point of this discussion is that the NRC system of regulation operates so as to define and enforce what is the "safe" construction and operationof a nuclear plant. Given this presumption-that the
NRC defines what is safe510-it is relatively easy toanswer the question of whether the safety of TMI-2
was compromised by the rush to commercial operation. We need only look to the regulatory action
taken by the NRC.
The first NRC action was
the issuance of a con511
struction permit to Met Ed.
As noted, such action
required the determination that construction of the
proposed facility would not be "inimical to the publichealth and safety." The second, and more important, regulatory assessment of TMI-2 safety came in
the issuance of the operating license. As previously
discussed, IE wrote a memo to the NRR stating that
all necessary work had been completed at TMI-2
andissuance of an operating license was prop512,513
er
Upon
the conclusion of the hearings re51a
garding TMI-2,
NRR issued an operating license
Met
Ed
to
operateTMI-2. That license wastobased on the findings that:

The Presumption of Safety Compliance

NRC is responsible for ensuring that each license
authorizes activity "not" inimical to the common defense andsecurity or to the health and safety of the502
public.
Specifically, NRC regulations provide thata license to operate a commercial nuclear powerplant shall be based on a finding that:

The processes to be performed, the operating procedures, the facility and equipment, the use of the
facility, andothertechnical
specifications. .. collectively provide reasonable assurance thatthe applicant will comply with the regulations in thischapter ... and that the health
5 3 and safety of the
public will not be endangered. oand that

The issuance of a license to the applicant will not,i n the opinion of the Commission, be inimical to thecommon defense and5 4 security or to the health andsafety of the public. oand:

By these directives, the NRC is required to define
505
what is necessary for the "safety of the public."
233

Construction of the Three Mile Island Nuclear Station, Unit 2 (the facility), has been substantiallycompleted in conformity with Construction Permit
No. CPPR-66 and the application, as amended, theprovisions of the Act,
515 and the rules and regulationsof the Commission.

There is reasonable assurance: (i) that the activities
authorized by this operating license can be con-

ducted without endangering the health and safetyof the public, and (ii) that such activities will be conducted in compliance with the rules and regulationsof the Commission.

Using information transmitted by IE, 516 the NRC(through NRR) believed TMI-2, as constructed, to be"safe." No deficiencies or violations of NRC requirements had been noted to challenge that finding.
However, as we have discussed, the period fromi ssuance of the operating license to commercial
operation was the crucial period in determining
whether there was a rush. During that period, inspectors were periodically on the site and maderoutine inspection reports. 517 Our review of TMI-2
i nspection reports for 1978 indicates no safetyrelated deficiency that can518,519
be connected with theaction previously analyzed.
In the case of the main steam relief valve replacement, GPU obtained an amendment to the
TMI-2 operating license, finding
no safety problem in520
the proposed replacement.
Additional postlicensing relief was obtained during this time period
as well, all with the required finding that the change
would not be inimical to the public health and safety.521

For example, Met Ed obtained permission to perform a test required by 522
the operating license earlier
than its specified date.
Met Ed received "relief"from performing another
test
because it was con523,524
sidered "impractical"
Again, however, thiswas done pursuant to a finding that such an exemption would "not endanger life or property ... and is525
otherwise in the public interest."
I n addition to these regulatory actions in 1978,the operators of TMI-2 had to satisfy conditions
built into their operating license. They apparently
did so, as letters from NRR granting the utility permission to proceed through the necessary modes ofoperation cite reports from inspectors 526
reporting Met
Ed's conformance with the conditions.
Finally, we have uncovered no Licensee Event
Reports (LERs) or other indications of problems withthe startup of TMI-2 during 1978 that might
be indi527
cative of an unsafe status of the plant.
I n sum, there is no record of NRC concerns that
TMI-2 was built or began operation in an unsafe
condition. With the assumption that the NRC defines what is safe, the inescapable conclusion is thatwhatever the effects of the rush to commercial
operation previously discussed, the safety of theunit was not compromised.
Without the Presumption of Safety

It is not surprising that some people do not accept the assumption that the NRC defines what is234

safe. They would dispute a conclusion, therefore,that without some NRC finding of a violation of its
standards, TMI-2 must be deemed to have been
built and operated in a safe fashion. This analysis
has two dimensions: the quality of the NRC definition of safe and the ability of the NRC to enforce its
standards. The latter is addressed first.
Even with the assumption that the NRC can properly define what is safe, critics have pointed out that
deficiencies in the NRC regulatory program might allow a licensee to violate that standard and still beallowed to build and operate a nuclear plant. The
basis of this assertion is that the NRC regulatory
program is an audit system. 528 Licensees are required by their license and the rules and regulationsof NRC to assume primary responsibility for the safe
construction and operation of the facility. NRC attempts to make sure that this responsibility is carried out through an audit inspection program. However, as presently designed, it would be impossible
for the NRC to observe and approve each action autility takes
in constructing and operating a nuclear
529
facility.
Critics point out that this creates the possibility
that safety violations go unnoticed and unpunished.
Despite an elaborate system designed to encourage
self-reporting, a utility has the ability to hide a safety
problem. 5 ° Even
531though this is done at great risk
to the licensee,
the possibility cautions against
the conclusion that a review of NRC records is sufficient for addressing the question of whether a rush
to commercial operation at TMI-2 compromised thesafety of the unit.
The more difficult contention is that the NRC
does not define what is safe and that NRC standards are inadequate in this respect. For example,
the failure of the NRC to devote adequate regulatory
attention to small-break loss-of-coolant accidents(LOCAs) has been identified as a safety problem
532
that has been underscored by the TMI accident.
The problem with this argument is that no otherstandard of safety can be used to measure thestatus of TMI-2. Some have apparently equated thenumber of problems encountered during the startup
phase at TMI-2 with a conclusion that the unit was,ipso facto, 533 unsafe. The NRC was aware, however, of these problems and found no safety ramifications. Indeed, the low dependability of nuclear units
i n the startup phase is well known. Are all units witha large number of problems during this period unsafe? What of those units such as TMI-1 that havesmooth startup programs? Are they safer?
Perhaps the most difficult standard is to equate
safety with "not having an accident." By this definition, TMI-2 was "unsafe" because it was the site of
the March 28, 1979, accident. This post hoc stan-dard is an impossible one to use for both a licensee
and a regulator. Such a standard ignores the complexity of a nuclear unit and places full liability on
the licensee
for what may be contributing534
causes.
In sum, although we recognize the problems withthe presumption that the NRC properly defines whati s safe, we know of no other standard to use.
Those safety standards discussed do not seem
helpful. Therefore, we are unable to conclude thatthe rush to commerical operation we have identified
played any role in the March 28, 1979, accident orcompromised the safety of the unit in general. Itsi mportance, as discussed below, is rather in its implications for the regulatory system as a whole.
5. IMPLICATIONS
Although no evidence suggests that TMI-2 wasplaced into commercial operation in such a fashion
as to jeopardize the safety of that unit, our investigation did identify a number of financial incentives
535
that are available to utilities that meet "artificial"deadlines. Indeed, quite apart from our conclusions
with respect to TMI-2, the most significant insight of
our inquiry was that the existence of these incentives could, under certain circumstances, tempt autility to compromise its commitment to safety,
which is essential to the construction and operationof a nuclear unit. To put it another way, our inquiry
has indicated that there is a "tension" between thenecessary commitment to safety required at a nuclear unit and the economic and regulatory pressures imposed on the utility that operates that unit.
It is necessary to expand on these implications
for a number of reasons. First, the current NRC regulatory system is of an "audit" nature. Some areasof utility performance are physically reviewed, in the
majority of areas NRC inspectors check only the"paper record" that the licensee maintains. If thepaper trail appears in conformance with NRC regul ations and standards, a utility will pass inspections.
I n essence, the NRC assumes that a licensee isoperating in conformance with its license and all applicable regulations.
Given a "less than scrupulous" licensee, the exi stence of incentives increases the potential that
corners will be cut in the safe construction andoperation of the plant, and still go undetected by the
NRC regulatory program. Obviously, if this occurred
on a widespread basis, the NRC would be unable toretain an audit program and the credibility of the entire system would be open to question.
Of course, penalties are imposed for violating an
NRC license or regulation, and some observers
235

would argue that a licensee would never intentionally risk a license for the "minor" incentives discussed
previously. With the assumption that this is true,
there is a second reason for being concerned withthe presence of these pressures on utilities that
operate nuclear units. The NRC is basically a technology regulator. Its staff of scientists and engineers are constantly attempting to give definition
to the commandment of the Atomic Energy Act that
nuclear power not be"inimical to the health and536
safety of the public."
I n other words, the NRC
attempts to define the minimum standards necessary for safety. But the NRC does not set theminimum, maximum, and only safety standards. As
stated previously, the NRC looks to the industry todevelop and implement more stringent safety standards for nuclear units. In short, implicit in all regulation of nuclear units is the requirement that theutility be committed to the safest possible operationof the unit,
Our point here is that this commitment, "aboveand beyond the call of duty," can be inhibited by the
incentives previously discussed. If a utility would
delete a system (not required by the NRC), safety ofa unit may not be enhanced. Thus, it is in this areaof self-imposed improvements that financial and regulatory pressures can have their greatest (negative) impact. It would be improper for the NRC to ignore this area, for, as noted, the premise of thecurrent system depends on a wholehearted commitment to safety on the part of each licensee.
In recognizing these complex problems in thecurrent NRC regulation of nuclear powerplants,
however, we are not suggesting that States should
assume a more active role in regulating the
economics of nuclear powerplants. For, as is discussed below, State regulation has, to some extent,
contributed to the current problem.
It should be clear that the implications discussed
below go beyond GPU and TMI-2. They affect theentire nuclear licensing system and the regulatoryenvironment in which licensees operate. Indeed,
TMI-2 is not alone in facing financial or other typesof incentives obtained by meeting some artificial
deadline. The Vermont Yankee nuclear unit was allegedly declared commercial before the end of acertain year to sell electricity to meet bond payments, as required in its indentures. 537 Prairie Isl and 2, operated by Northern States Power Company, was declared to be in commercial operation 4days after criticality, and the utility is currently involved in a tax protest with the IRS because of
I RS's refusal to recognize Prairie Island 1 as placed538
i n service in 1973.
In an unusually candid statement, the executive vice president of Toledo Edison
Company testified before the Ohio PUC that theDavis Besse nuclear unit was declared commercial
i n consideration of more than "physicaland opera539
tional engineering status of the unit."
He said:

One example of this problem is the authority of
economic regulators to disallow portions of theclaimed value of a completed plant as improper.
This can occur in a number of situations, but theend effect is the same: utility shareholders bear theburden of whatever has been disallowed. Because
the management of a utility is responsive to shareholders' concerns (if they wish to remain in office),
the goal of management is clear: reduce the possibility of such disallowances.
One method by which a portion of the completed
plant can be disallowed is FERC's Electric Plant Instruction 9D provision that AFUDC for a test period
greater than 120 days must be justified. Although
this provision may be more of a threat than aweapon actually used, utilities seem to respond toeven the possibility that FERC might follow
through542
on the threat. For example, at TMI-2,
GPU wasanxious to minimize the period of testing greaterthan 120 days.
The rationale behind Instruction 9D is not illogical.
Some method of limiting the abuse of AFUDC(through a longer-than-necessary test period)
seems reasonable, but that evaluation cannot bemade in a vacuum. Any analysis as to the proprietyof the length of a test program necessarily involves
questions of nuclear safety and the readiness of theunit to begin full operation. The NRC has recognized as much in establishingstandards for the543
l ength of test programs.
Under these circumstances, FERC probably
should yield to considerations of nuclear safety andthe responsibility of the NRC. FERC's legitimate
economic regulation could be served by presumingthat a nuclear unit was constructed in the most
expeditious manner possible consistent with nuclear
safety. If a legitimate concern was raised in a
specific case, alleging an unnecessarily long test
period, the NRC should be available to offer an opinion as to whether the lengthened test program
could
544
be said not to have contributed to safety.
A second method by which utilities are faced withpossible disallowance of a portion of plant value isthrough specific challenges to inclusion of certain
costs. For example, at TMI-2, the cost of replacing
the main steam relief valves was challenged by thePennsylvania Office of the Consumer Advocate as"imprudent management." Although not acceptedon that basis, PaPUC did disallow a portion of thereplacement
cost in the rate base associated with545
TMI-2.
The Office of the Consumer Advocate argument
is not unique. PUC staffs have generally been concerned with the possibility of "goldplating;" that is,

There were other financial considerations whichhave to be considered and the impact on the financial health of the company, starting and taking of[tax] depreciation being one of the significant items.
These things are all considered.54o

Generically, a review of NRC records shows that
25% of all plants currently holding operating
li censes were declared to be in commercial operation in December of some year. 541 This percentage
seems higher than a mere chance would dictate.
Are these examples significant? Do they indicatethat the safety of nuclear units has been compromised in some fashion by attempts to obtain incentives? Those questions are impossible to answer
without the same kind of detailed investigation weused to examine the history of TMI-2. Rather, what
we propose to discuss in this "implications" section
is a "worst possible case" scenario. If there could
be a licensee who would compromise the safety ofa nuclear unit to obtain incentives, what should be
done?
The incentives that exist in this area have been
discussed at length in the first section of this report.
To understand why those incentives persist andhave complicated this gray area requires an understanding of the systemic problems we have uncovered in this area. The final section of our reportdiscusses possible changes that could be made torectify the situation, changes for both the NRC andother institutions.
Ambiguous Regulatory Responsibilities

In theory, there is a clear division of authority
among the regulatory bodies involved in a nuclear
powerplant. In broad terms, one would expect the
NRC to regulate nuclear safety, the public utility
commission (PUG) to regulate retail rates associatedwith the plant, and FERC to regulate the wholesale
rates associated with the plant.
However, we have discovered-not surprisingly-that regulation does not fit into such neat little boxes when a nuclear plant is concerned. In
reality, the economic decisions of PUCs and FERC
could conflict significantly with a utility's commitment
to nuclear safety. It is this spillover effect thatcreates ambiguity for a utility. In trying to satisfy an
economic regulator (or obtain an incentive under thecontrol of that regulator), a nuclear licensee may beconsciously allowing that regulator to make a safety
determination.
236

the inclusion of unnecessary costs in546
a plant so as
to boost its value abnormally high.
This mayi ndeed be a legitimate concern, but when dealing
with a nuclear unit, the distinctions between "goldplating" and "commitment to safety" become unclear. In seeking to avoid allegations of the former,
utilities may back away from the latter.
The ultimate effect of these kinds of pressures isexactly contrary to what should be encouraged.
There should be incentives for utilities to go beyond
NRC minimum standards of safety and invest in innovative, improved equipment, rather than disincentives for doing so. Utilities, it could be argued,
operate at the "margin" set by the NRC because to
do otherwise invites attacks of "goldplating." No
matter how committed management is to nuclear
safety, an investor-owned utility cannot fund such acommitment indefinitely out of shareholder (as opposed to ratepayer) funds. 547
To cite one example of the effects of thiseconomic oversight on nuclear safety, we point
again to Vermont Yankee. In 1976 NRR asked Vermont Yankee to voluntarily shut down its boiling water reactor so that a study could be made of a genericproblem.
Vermont
Yankeeagreedpresumably in the interest of general improvementof reactor safety. While the unit was down, more
expensive replacement power was purchased tosupplant the Yankee power and this higher cost
was passed on automatically to consumers throughfuel adjustment clauses.
By order of the Governor, the State Public Service Board held a hearing on the propriety of billing
customers for this replacement power. Intervenors
argued that because Vermont Yankee did not receive an NRC order to shut down, it was improperto have done so voluntarily and pass the costs on
to customers. Shareholders, not ratepayers, shouldbear the cost of the replacement power above what
Vermont Yankee costs would have been, they argued. The Vermont Board rejected the argument,54
but not without considering it on its merits. s
Does economic regulation such as the Vermont
Yankee example improve reactor safety? It seems
doubtful. The added delay in obtaining an order andthe potential for legal arguments do not seem to add
at all to safety.
As in the FERC example, there may be valid reasons for PUCs to be concerned about goldplating
and imprudent management in nuclear units. But
also as in the FERC example, the detrimental impact
of such analyses on nuclear safety by the PUCs appears to outweigh any economic savings to rate
payers. With the assumption that PUCs have ap-

237

proved the construction of a nuclear unit as necessary for a utility's power capacity, its attention
should not be devoted to a detailed review of thecosts of each component thought necessary by theutility. If valid issues of goldplating are raised in aproceeding involving a nuclear unit, again the NRC
should be available to testify on a single question:
Could it be said that the identified expense is unnecessary to nuclear safety?
Ambiguous Regulatory Standards

If it seems implausible that economic regulators
have unwittingly impacted on nuclear safety,
perhaps the answer lies in the ambiguity that surrounds this entire area of regulation. One of thestriking conclusions that occurs to a person looking
at these issues for the first time is that this is indeed
a gray area; no regulator appears to have clearlytaken the responsibility for deciding when a plant isready for transition from a massive construction
project involving high technology to a business asset that produces revenues.
Perhaps one reason for this ambiguity is the typeof standards employed. For example, an examination of the different standards and meanings of"commercial operation" (or equivalent phrases) indicates the confusion in this area. As noted previousl y, a declaration of commercial
549,55operation is basicallya management decision.
o It affects the accounting treatment of the plant by the utility 551 and552
has perhaps some other internal purposes.
The
criteria for making that determination and its impact
on regulators are not as clear.
The issue is one of present concern, having been
involved in several regulatory proceedings involving
553
nuclear units. As previously discussed,GPUwent to great lengths to set forth its criteria for declaring TMI-2 commercial to the Pennsylvania and
New Jersey PUCs. Similar issues have arisen in
Ohio, where the Davis Besse unit sought to be included in Toledo Edison's rate base because
it had554
been declared "in commercial operation."I n theDavis Besse proceeding, a vice president of the util-,
ity said his company has compared criteria of utilities around the country for declaring a nuclear unit
in commercial operation and had found no common
555
set of rules.
The NRC must assume some responsibility forthe confusion in this area. The term "commercial
operation" is mentioned several times in NRC regul ations, 556 but in each instance the term is used asa point of reference, not as a point of regulatory action. For example, in incorporating provisions of theAmerican Society of Mechanical Engineers code in
10 C.F.R., the NRC557
did include references to "com-be imagined that "commercial operation" and thedate on which the PUC recognized a unit in ratemeans of expressing a particular point in time.

rate base,mercial operation,"but because no penalties orbase would be the same. That is not necessarily

action flows from that event in any other regulations,
it must be seen as no more than a convenient558

the case.
I n Pennsylvania, where CWIP is not allowed in

The NRC has also promulgated a definition of"commercial operation." In Regulatory Guide 1.16,

useful" status.

the term is defined as:

ambiguous as "commercial operation."FERC

has stated that there is no set formula for determin-owner to be available for the regular production ofelectricity, usually related to the satisfactory com-i ng whether a unit is "used and useful." 568 Rather,pletion of qualification tests as specified in the pur-

FERC states only that "reasonable time should be

9chase contract and to the accounting policies andcome sufficiently completed to be reasonably reliable for 569
service for the purpose for which it was inallowed for test periods ... and ... for the plant to be-

Admittedly, the definition is somewhat circular. It is

tended."made even less useful by the fact that Regulatory

Guide 1.16 is an advisory guid e for completing reporting requirements to the NRC for operating un-

The similarities with the GPU-defined

criteria of "commercial operation"-that is, the completion of the FSAR test program-is obvious.

However, despite assertions that the two terms

its. 561 It has no regulatory impact other than as gui-are identical, the Pennsylvania Office of the Consumer Advocate has pointed out that "commercial
operation" is a technical definition of the utility, but

dance that some data be provided.
We could find no provision of NRC regulations
that imposed regulatory responsibility on the NRC"used and useful" is a legal finding that determinesover the declaration of , commercial operation.

when consumers will begin paying for the unit.

Numerous depositions with
NRC officials of all levels562
confirmed this finding.

Confusion is possible because

the definition of "used and useful" appears
to be as567[T]he date that the unit was declared by the utility

practices of the utility

a practice seems to have developedof equating "commercial
operation" with "used and
566,W6

Although the NRC is

The distinction is useful for several reasons. First,"used and useful" is the languageof the statute, not570

responsible for granting an operating license, ap-"commercial operation."proving progressions to necessary modes of preo-

peration, and finally granting mode 1 (power opera-

Second, as previously

noted, simply declaring a unit "in commercial opera571

tion) authorization when a licensee has completedtion" will not bring automatic rate recognition.

operation.

useful" before any return flows to the company. 572

all conditions identified in its license, it is not specifically involved in the movement to commercial

The PUC must consider that unit in the forthcoming
rate application and rule that it is indeed "used andOther than the IE review of the power

ascension program, there is no NRC input into theutility decision to move the project into a moneymaking proposition.
FERC is interested in the accounting change thatthe declaration of commercial operations has on theutility's books: shifting the plant from the CWIP ac-

I n summary, "commercial operation" and "usedand useful" may be used in similar fashion by PUCs,
but they do not indicate the same point in time. Asa general rule, apparently a declaration of commercial operation must precede consideration by theregulators
as to whether the unit is "used and use573-575

count to the plant in service account. However, no-ful."where does FERC define the criteria for declaring aunit to be in commercial operation. As has been
noted in testimony before the Ohio PUC, the closest
FERC definition is the inference in Electric Plant In-

struction 9D that 120 days after testing begins, auseful."plant should be declared in commercial opera-tion.

Ignoring this distinction only compounds

the ambiguity in this area for all involved. For example, utilities may seek to declare the unit commercial
earlier than it should be in order to meet that
precondition
to consideration of being "used and576
Alternately, utilities may hold off declaring a unit

commercial until the exact moment when "used and563

Most questions concerning "commercial operation" arise before PUCs, for they have the responsi-

useful" status is assured, to minimize the loss of
AFUDC577that accompanies the accounting

bility for determining when a unit is going to bechange.

recognized as "used and useful" (when the ratepayers will begin paying money toward its operation and construction). In a logical system, it might

Turning finally to the IRS, we find-as previously
noted-that the IRS does not use the term "commercial operation" (or "used and useful") in deter-238mining when a unit is first placed in service for tax
purposes. Rather, the IRS has established, on an
ad hoc basis, a definition of placed in service that isdifferent from any other point recognized by regulators. This approach presents two problems.
First, as a theoretical matter, it would be helpful if
all regulators used the same physical event as thepoint at which recognition of the nuclear unit as abusiness asset would be made. For example, if final
completion of the FSAR power ascension test program indicates that a unit hascompleted its con578,579
struction and testing phase,perhaps all authorities should recognize that as the moment ofbusiness recognition; that is, a unit that is in "commercial operation," "used and useful", and "placed inservice" all at the same event. Regulators have different interests in regulating, and therefore, theirstandards must sometimes vary, but it is difficult to
see the importance of the couple of months difference to which the present standards give rise. Balanced against the need for clarity in dealing withthis complex process, the IRS should develop a
more consistent standard with the other institutions
involved.
Second, even if the IRS decided not to develop a
consistent standard, it would have to turn its attention to the current definition of placed in service.
Through a number of regulations, letter rulings, and,especially, revenue rulings, the IRS has attempted togive definition to the term. In the process, thenecessary criteria have become more complex
until -in the most recent letter ruling-at least one
I RS interpreter believes "placed in service"
5 is roughly equivalent to "commercial operation." so For example, if it is necessary for a nuclear unit to581
in"operate at its rated capacity without failure"
the year in which it is placed into service, what is"rated capacity"? What is a "failure"? How longmust a unit operate "at its rated capacity without
failure" in the "placed into service" year? One
month? One day? Ten minutes? The answer of
the IRS is, of course, that such matters will be decided on a case-by-case basis.
However, one can imagine that a utility just completing a billion dollar unit and attempting to plan for
its tax effect would be concerned with the ad hoc
approach. The IRS needs a better, more technicallyunderstandable, set of criteria for allowing tax treatment of a major nuclear generating unit. 582
I n sum, the regulatory agencies have not coordinated their responsibilities in this area. The
numerous variations and understandings of the term"commercial operation" are simply symptomatic of

this fact and also indicative of the ambiguity overwhich responsibilities the agencies should exercise.
Conflicting Responsibilities of Regulatory Authorities

It' follows inexorably from the foregoing identification of ambiguous responsibilities and ambiguous
standards that conflicts among the various regulatory bodies would arise in this area. In our investigation, we found numerous examples where an agency, in attempting to regulate what it perceived as its
area of responsibility, actually came into conflictwith the authority of another agency. In one sense,
this is a problem only for the utility. It must find ameans of either reconciling different agencies' instructions or simply absorbing the cost of choosing
one over the other. However, more broadly, it is amatter of general concern when the aims of one regulator are confused by the actions of another. Thisi s especially true when the issue of nuclear safety is
i n the middle.
We have already discussed how the practice of
PUCs and FERC in examining the value of a completed nuclear plant may cause utility managements
to be reluctant to explore new safety innovations. 583 Either through direct challenge to specificitems included in the unit or through challenge to the
FERC andlength of time it took to complete the unit,584
may create
PUC staffs and consumer advocatesan inhibiting effect on utilities.
However, this is not to suggest that FERC and
PUCs act in concert on all matters. In fact, we haveuncovered situations in which a PUC ordered one
rate treatment and FERC ordered another for thesame event. For example, in evaluating whether
Philadelphia Electric Company's (PECO) share of
the Salem 1 common plant was "used and useful,"
PaPUC instructed the company to ignore its earlier
declaration of commercial operation and continue585
toaccrue AFUDC on half of the common plant.
PECO protested that under the Uniform System of
Accounts, FERC would probably not allow accrualof AFUDC beyond a declaration of commercial
operation. FERC has not yet ruled on the issue but
the staff has indicated that precedent suggests thecommon plant will have to be considered "plant inservice." In effect, there will be two different treatments of the same plant: on the one hand, Pennsylvania retail rates will not recognize the Salem 1
common plant as a portion of rate base, but willcontinue to accrue AFUDC on a completed plant,
and on the other hand, wholesale rates will 586
recognize PECO's common plant share of the unit.

239

There are numerous examples of FERC and
PaPUC
using different methods of treating the same
587
event.
I n theory, there is no problem with suchseparate approaches, -r88 but the effect on a utility
must be one of attempting to be "all things to alI regulators." As GPU Treasurer John Graham stated:

I would say that as we try to go about our business,
we see areas where there may be a conflict
between what one agency wants and what anotheragency wants and we have to try to work out ouraffairs in such a way [as] to accommodate all of
those interests.W9

There is even the potential that the rate commissions (PUCs and the FERC) will come into conflictwith the IRS. As previously discussed, because the
I RS "placed in service" standard is not equivalent to"commercial operation" or "used and useful," a utility
possibly will receive tax recognition of its investmenti n a nuclear unit before rate treatment. 590 Indeed,utilities are under a standing obligation, as imposedby their PUCs, to take tax advantages as soon as
591
possible, to reduce the need for revenues.
Presumably, utilities will take advantage of thedifference between the two standards and take tax
credits and depreciation allowances as soon as
possible.
PECO's experience with the Salem 1 unit indicates some problems with that approach. PECO declared Salem 1 commercial on June 30, 1977. However, the IRS considered the unit placed in service
on July 1, 1976, and had consequently allowed thecompany to obtain depreciation for the 1976 tax
year. On the argument of the PUC staff and Officeof the Consumer Advocate, PaPUC reduced the
AFUDC associated with Salem 1 by the amount of
the tax advantages received by PECO before thedate of commercial operation. PaPUC held that thisamount should, in essence, be "flowed-through" tothe ratepayers
and not accrue to the benefit of the592
company.
The point is that as confusing as the existence ofdifferent standards may be, the regulatory bodies
have compounded the problem by refusing torecognize the authority of others to fulfill their statutory functions. If Congress intended all corporations(including utilities) to 593
receive ITC at the earlier
placed in service date,i t seems inappropriate for
PUCs to redefine, on their own
initiative, the proper
594
distribution of those benefits.
Although the NRC does not fit directly into eitherof the conflicts discussed, its interests are involved.
The NRC has traditionally disclaimed any interest in
the financial affairsof its licensees or the impact of595
other regulators.
It does, however, have responsibility by the requirement of both the Atomic Ener-240

gy Act596 and its own regulations 597 that a licensee
must be "financially qualified" to construct andoperate a nuclear facility.
The rationale for such a requirement seems obvious. If financial matters cause a licensee to cut
corners in either the construction or operation 598 ofa facility, the NRC should be concerned. As previously discussed, such a temptation would be inconsistent with the commitment to safety required of allli censees.
I n reality, however, the "financial qualification"
analysis has been less than stringent. Most of theattention at the NRC has been focused on the initialconstruction permit or operating license adjudications proceedings. If an applicant could demonstrate to the staff that it had the necessary financial
resources to build the unit, the NRC would, inessence, deem the licensee financially qualified forthe life of the license.
I ndeed, the best indication of the relative unimportance of the financial qualification analysis is thefact that the staff has (at NRC invitation) proposed
reducing its scope. Under a proposal
currently599,
pending before the Commissioners,
if a licensee(1) was a regulated utility and (2) held a bond ratingof "A"or better, it would be deemed financially quali600
fied.
This is not the forum to debate the meritsof this proposal, but it seems fair to say that thiswould reduce even the somewhat superficial scrutiny currently given to the financial position of theutility.
The point is that even under the present system,
there is no ongoing analysis of the financial condition of a licensee vis-a-vis its ability to operate anuclear facility. The section at NRR that evaluates
financial qualification for purposes of the construction period or operating license proceedings is not
equipped to undertake a detailed ongoing analysis.
Furthermore, IE specifically denies an interest in thefinancial position of the utility while it is involved in
inspections. As we were told by numerous IE personnel,
that is considered outside its responsibili601
ty.
There is apparently no system at NRC forgatheringand evaluating these data on an ongoing602
basis.
As is discussed in detail below, we believe this tobe a serious deficiency. Combined with a failure to
maintain adequate contacts with the economic regul ators, it leaves the NRC blind to important financial
considerations that may have an impact on thesafety of the unit. Postulating a licensee that would
be willing to compromise safety-and might do so
to satisfy conflicting regulatory demands-there isno clear indication that the NRC would becomeaware of the action.

necessary funds" to construct and operate a nuclear powerplantin order to be found "financially
603
qualified."
Two factors discussed by the Commission in reaching a decision in that case were thebond rating of the utility and the pending rate increase requests . The premise of this analysis
appears to be that existence of sufficient funds (or"reasonable assurance" or obtaining those funds) at
the start of the licensing process will militate against
the development of financialpressures which might
605
affect the safety of the unit.
As this report has demonstrated, however, there
are numerous points in the construction and operation of a nuclear plant when the potential to improvea utility's financial position could create pressures
which conflict with the commitment to nuclear safety, earlier identified. As a dissenting member of theAtomic Safety Licensing and Appeal Board said in
Seabrook:

6. RECOMMENDATIONS
The combined information obtained in this inquiry,
from both TMI-2 and generic cases, indicates aneed for change in the regulation of nuclear powerplants when decisions regarding economic recognition of the unit are being made. In the common, but
ambiguous, phrase that has been at the center ofthis report, "commercial operation" must be better
regulated.
Our recommendations, it might be suggested, go
beyond TMI-2 and propose broad-ranging andsweeping changes in some fundamental aspects ofutility regulation. However, as the foregoing madeclear, this is an area of complex and overlapping interrelationships. Restricting recommendations to
TMI-2 or the NRC alone would not reach systematic
problems and the other institutions.
Having said that, we recognize that each agency
best knows its strengths and weaknesses. We
presume that having been shown the potential problems that exist in this area, agencies will take thenecessary and appropriate action. Our recommendations, therefore, are more in the way of example
than completely thought-through solutions. We propose them as further restatements of what we perceive as key problems in this area.
Our recommendations break down into two major areas: those that affect the NRC and those that
affect non-NRC institutions. Finally, we propose
some long range studies that our inquiry has suggested might be of benefit.

[T]here is a need to avoid a situation in which financial pressures on the applicant become so persuasive as to influence the manner in which theplant is constructed ... financial constraints can playa heavy influence on day-to-day decisions.... In insidious fashion, each such decision (less testing,lower quality materials, borderlike workmanship)even though not consciously designed as believedto do so, increases the risk from an eventual accident.6m

We therefore recommend that the NRC expand
the "financial qualification" analysis to include thegathering of data during the operating life of the unit,
with special emphasis on the year in which the unit
i s completed and declared in commercial operation.
Rather than607,608
reduce the depth of financial qualification review,
the NRC should encourage its
expansion. Rather than focus on construction permit and operating license proceedings,
the financial qualification review should be expanded to become a "financial analysis" review, which looks to
the impact of business activities on the commitment
to nuclear safety.
Furthermore, the NRC should provide the necessary personnel and authority to collect and analyze
business data. Rather than work with outdated annual reports and newspaper clippings, the NRC staff
should have access to the most intimate financial
details of a licensee's operations. This would enable a prospective analysis of the pressures the utility faces in the future and an evaluation of the possible effect that pressure would have on nuclear
safety. Should a problem in this regard come to theattention of the NRC staff, it would then be in a position to meet with the licensee to discuss the ramifi cations. At a minimum, such a meeting would alert
a licensee of the NRC's concern.

NRC Recommendations
1. The NRC Should Establish an Expanded Financial
Analysis Office to Monitor Situations in WhichBusiness Considerations May Impact on Nuclear
SafetyThe NRC has been deficient in recognizing thefundamental conclusion of our investigation. That
conclusion, again, is that attempts to obtain incentives and deal with regulatory pressure could
compromise the commitment to safety required of a
nuclear unit licensee.
However, the NRC has implicitly recognized thei mportance of financial pressures. In a somewhat
backhanded fashion, the requirement that a utility befinancially qualified indicates an awareness of the
impact that the "business" side of a utility can haveon nuclear safety. In a decision involving the
Seabrook (N.H.) nuclear station, the Commissioners
established that a utility need only demonstrate thatit has "reasonable assurance of obtaining the
24 1

i ncentives have been identified. This would send amessage to the utility: Proceed at whatever pace
you think appropriate to obtain the incentives thatexist, but the site will be subjected to additional
scrutiny during that period to prevent the cutting ofcorners.
Parenthetically, the NRC has begun the implementation of a resident inspector program that611
would place an IE inspector at each nuclear site.
We suggest a resident inspector might be in a good
position to observe changes in the pace of construction, which may be indicative of a push to meet
artificial deadlines.
In addition, resident inspectors could provide anoutlet for worker dissatisfaction or safety concernsthat arise from increased production demands.
Many times, in the course of this investigation, wewere told that workers would not go to an NRC official with an allegation of improper work
6312 or rush beThe NRC
cause they feared losing their jobs.
must increase its protection of such employees topromote free communication of safety concerns.
Perhaps a resident inspector program is one
method.

2. The NRC Should Establish Better Communication
and Coordination with the "Economic Regulators"

A second significant failure in this area has been
the lack of coordination between the NRC and
PUCs. Far from assisting each other in understandi ng the complexities of putting a nuclear unit into
commercial operation, the NRC staff has not attempted to stay informed of relevant PUC decisions.
I n the apparent belief that action following the issuance of an operating license and mode 1 authorization is not of importance, the NRC staff has ignored the impact of PUC and FERC decisions on
those milestones.
As the NRC establishes an expanded financial
analysis office, it should specifically instruct the
NRC staff to develop better lines of communication
with the PUC staffs, including joint annual meetings
to review matters of mutual concern. Although suchmeetings would entail some cost, the additional information would assist the NRC licensing system.
3. The NRC Should Establish a Better System at IE
for Balancing the Pressures Created by Financial
Incentives

4. NRC Offices Should Strictly Scrutinize the Power
Ascension Test Program and Any Problems
Encountered on the "Critical Path" to Commercial
Operation To Prevent Any Compromising of Safety

At the same time that a Washington-based office(presumably in NRR) is developed to keep track of
relevant financial and regulatory data, field offices of
the NRC must become more sensitive to the incentives that_ may be pushi ng_ utilities toward certain
dates. Regulatory systems are built on a system ofchecks and balances; if there are advantages tosome action that is detrimental to the public interest,
regulations, inspections, and enforcement are posedin counterbalance. If our assertion is true that there
are financial incentives for completing a nuclear unit
by certain "artificial dates," what is the balancing regulatory action? Our investigation has not indicatedany agency that even accepts responsibility for thisarea. We would propose that IE establish a system
for informing inspectors in the field, of identified
financial incentives and of important dates for obtaining those incentives for utilities constructing nuclear plants. 610 The field inspectors could then increase their monitoring during those crucial periods
to make sure that no corners are cut in meeting thefinancial deadlines.
At the same time, IE headquarters could require
reports on observations during these key financial
periods to better assess the generic implications offinancial incentives. Based on such an analysis ofidentified violations during these periods, IE mightwant to create a specially trained team of inspectors who would descend on a site where financial

I n addition to the recommendation that the NRC
become more sensitive to the possible impact offinancial concerns on nuclear safety, there is muchthe NRC can do to tighten the existing regulatory
system such that a rush to commercial operation
will not impugn minimum NRC safety standards.
Our investigation into allegations surrounding
TMI-2 focused on two major developments during
the startup test program that were key in enabling
completion of the plant by the end of 1978: thepace of the power ascension test program and themain steam relief valve failure. We would suggest
that, generically, the NRC should pay close attention
to similar developments in all units as indications ofpossible rushes to meet artificial deadlines.
The power ascension test program, as identified
in the FSAR, need not be complete to declare aplant in commercial
operation under current
614 regula613
615
However, corporate,tax
tory practices.
and regulatory 616 pressures are moving utilities toward a linking of these two events. Therefore, the
NRC should pay careful attention to completion of
power ascension testing. This involves more thanthe current IE observation of one or two major
617
Rather, we recommend that an NRC intests.
242

spector personally view each power ascension test
i n mode 1 and certify acceptance of results within
the criteria set forth in the FSAR. At the completionof the program, the NRC inspector would issue a final certificate so indicating. Following a careful
power escalation,
the unit would then be allowed
to proceed to full power and, if the utility sodesired, 619 be declared in commercial operation.
The NRC inspector should be concerned withseveral matters during this period: not only the acceptability of the tests, but the pace, the effect onworkers, fi20 and variations from the FSAR scheduleshould be of interest to the NRC. If, at any time theI E inspector felt that the testing schedule wasproceeding too rapidly or was overtaxing the workforce, a full investigation (with possible suspensionof the program) would result.
Our investigation into the TMI-2 main steam relief
valve problem also demonstrated that major equipment deficiencies which occur on the "critical path"of commercial operation create pressures on theutility to complete repairs as soon as possible.
Recognizing the potential for compromise to remain"on schedule," we recommend strict NRC scrutinyof any such deficiencies that arise during the startup
test phase. This scrutiny would involve (1) a licensee event report (or its equivalent) on the
discovered deficiency, (2) mandatory filings with
NRR assessing the safety impact of the deficiency,(3) filings with the financial analysis office assessing
the financial impact of any delay, and (4) strong IE
presence during the period of repair.
As discussed above, GPO's action with respect
to its main steam relief valve problem was in full accord with
NRC regulations and good business prac621
tices
Our concern is that neither NRR nor IE appeared to be concerned about, or interested in, thepressures on theutility to complete repairs on its
622"critical path."
Given our hypothetical "worst
case," such an attitude might not be proper.
5. The NRC Should Examine the Status of the
FSAR Listing of the Power Ascension Tests To Be
Performed

A number of minor items also deserve NRC attention. For example, the FSAR section that deals
with startup testing can be so cryptic as to be usel ess. The NRC should require licensees to list (1) all
tests scheduled; (2) all tests required by NRC regulations,with citation to each provision in the regula623
tions;(3) all tests that the NSSS has suggested;(4) all tests proposed by others; and (5) all tests
that are optional and subject to deletion. A realistic
estimate of the time period necessary to complete243

the program-both with major deficiencies andwthout-should be included in the FSAR. Only withsuch a complete before-the-fact list of utility intentions can NRC personnel be in a position to judge
whether rushes in the schedule are occurring.
At the same time, the legal ambiguity regarding. 624
the status of the FSAR should be addressedIfa licensee deletes tests listed in the FSAR, the NRC
should-at a minimum-be informed of that decision. Whether that specific test is necessary forsafety or not, its deletion may be indicative of abroader problem of which the agency should beaware.
Finally, the difficulty of knowing when to begin
scrutinizing a unit for signs of a rush remains.
Although we have recommended changes that affect, primarily, the startup phase, previous recommendations of (1) increased NRC sensitivity to financial impacts and (2) increased IE involvement withthose issues should begin with issuance of a construction permit. Hence, there would be, under ourrecommendations, increased oversight during theconstruction phase, as well as during the startup
testing phase (after fuel load).
Recommendations for Other Institutions
Recommending that the NRC do a better job inthis area is only the first step in changes
that must
625
occur. For, as previously discussed,
the NFIC
system is designed to impose minimum safety requirements through an imperfect "audit" procedure.
Without a utility commitment to nuclear safetyabove and beyond NRC requirements-there isserious question as to whether the entire regulatory
process can succeed. It has been argued that mostutilities are committed to nuclear safety,
626as a matterof ethics and good business sense.
However,
our concern is for the "worst case" licensee who
would be tempted away from that commitment by
the existence of financial and regulatory pressure.
For the benefit of the entire system of regulation,that "gap" must be plugged.
This requires recommendations for changes not
only in the NRC, which must address itself only tominimum safety standards, but in other institutions
as well. In effect, we are recommending a twopronged approach: (1) increased NRC sensitivity
and action to make sure that minimum safety standards are not compromised and (2) the eliminationof incentives that might tempt a utility away from its
commitment to safety. Our recommendations in thissecond area reach three institutions: State PUCs,
FERC, and the IRS.

6. PUCs Must Recognize the Unique Problems
Associated with Challenging Utility Decisionmaking
as a Nuclear Unit

State PUCs must come to a better understandingof the complexities of building and operating a nuclear powerplant. Both utility executives and PUC
commissioners have fallen under the illusion that nuclear stations are like any other generating unit, except for the fuel source. That "except" is a crucial
distinction. Nuclear powerplants are unique and re627
If that self-evident truth
quire special attention.
i s recognized, then it is not inconsistent to realizethat in regulating the economics of these units,
State PUCs have special responsibilities and must,at times, make special arrangements for nuclear units. Although we recognize the added complexitythat treating nuclear units differently from othersources of generation may cause PUCs, we seesuch differentiation as unavoidable.

8. CWIP in the Rate Base Should Be Allowed for
Nuclear Units by PUCs To Reduce the "Lump Sum"
That Is Otherwise Accumulated

A second major problem in the PUCs requiresconsiderably more thought and perhaps legislative
action. However, allowing utilities to accrue AFUDC
sthrough the construction life of a nuclear unit
creates a large incentive for the utility to complete
the unit by a certain "artificial" date. The magicphrase "used and useful" releases large sums ofmoney to the utility, including vast amounts of
AFUDC.
To reduce this presssure on a single point in
ti me, PUCs consider recognition of nuclear plant
CWIP in rate base. That is, during the constructionof a nuclear unit, a utility should be allowed to earna rate of return on the money that has been expended into the unit to that time. The goal is to
reduce a utility's incentive to rush to meet a certain
date when it nears the end of construction and, instead, to spread out recognition of the unit over thelife of the construction project. If, for some reason,
the unit was eventually not found to be used anduseful," the money collected under CWIP would
have to be refunded by the company.
This recommendation is not without problems.
There are serious questions among utility regulators
as to whether CWIP in rate base is proper. For example, one argument against its inclusion is thattoday's ratepayers should not have to pay for
tomorrow's plants. There are many other difficult
questions concerning CWIP in rate base, but they
can be debated elsewhere. Our recommendation ismeant simply as one example of a means to reduce
the pressure of a "one-shot" inclusion of a billion
dollar facility in a utility's rate base.

7. When Nuclear Units Are Involved, a Truly Future
Test Year Should Be Employed by PUCs

Our investigation into the TMI-2 case indicatedthat the importance of the Penelec 1978 test year
may have influenced628
GPU into completing the unit
This
event was possible
before that deadline.
629
was not far enoughbecause the future test year
i n the future to avoid the "present" catching-up..
Thus, because of delays in the regulatory process,the Penelec rate proceeding was ongoing during thetest year. Rather than be either a "historical" or "future" test year, Penelec had, in fact, a "present" test
year. That increased the pressure to be
63oin commercial operation before the case ended.
We recommend that when a nuclear unit is being
i ntroduced into rate base, a future test year should
be set far enough in the future that there is nodanger of overrunning the test year. Thus, in thePenelec case, a future test year of June 1979 toJune 1980 might have been advisable. The further
the test year is placed in the future, the greater the
reliance on projections and estimations. However,
PUCs have vast discretion to rectify any overpay631
ment by ratepayers due to such imperfections.
Furthermore, the difficulties of scheduling PUC
proceedings create problems of running into the testyear.
One solution to this problem was developed in
California, where the PUC has committed itself torenderinga decision in a case before the test year632
begins.

9. PUCs Should Define and Recognize a Distinction
Between a Nuclear Plant in "Commercial Operation"
and One that Is "Used and Useful"State PUCs must also find a means of better defining the relationship between "commercial operation" and "used and useful." If the two are identicali n usage, PUCs should so recognize. If the phrases
i ndicate a difference between technical and legal
meanings, that too should be stated clearly. We
have recommended that a standard definition ofcommercial operation include completion of the
FSAR-identified tests. We have also recommended
that the NRC certify completion of the power ascension test program. It is consistent, therefore, to244

recommend that a PUC require a utility to submit
such an NRC certificate before declaring a utility to
be in commercial operation and seeking that it bedeclared "used and useful."
In this context, "used and useful" is a final findingthat the unit as completed is capable of serving the
ratepayer in a reliable fashion. If CWIP in rate basehas been allowed in the past for that unit, a findingof "used and useful" eliminates the possibility that
CWIP will need to be refunded by the utility. If no
CWIP in rate base has been allowed, of course, theentire plant costs would become part of the ratebase on the finding that the unit was "used and useful." At a minimum, the standards for that finding
should be clear-which at present is not the case.
Perhaps the greatest change in State PUCs is onethat
We have detailed extensively 634 how thepotential for disallowance of AFUDC causes utilities
to hesitate to go beyond the bounds of NRC
minimum safety standards. It is doubtful that PUCsand Offices of Consumer Advocates understandthat this could be the effect of their economic challenges to a utility's claimed value of a nuclear plant.

PUCs Should Attempt To Improve a Dialogue
with the NRC and Other PUCs To Coordinate
Nuclear Plant Treatment
11.

Our final recommendation for PUCs is the converse of our earlier recommendation for the NRC:
We recommend improved dialogue between agencies involved in regulation of nuclear plants. In
recognition of our earlier assertion that regulation inthis area does not fit into "neat little boxes," State
PUCs and the NRC should maintain an ongoing discussion of each other's relevant concerns. For example, should the NRC become aware of a "present
test year" problem, it might suggest to the PUC staff
that a stipulation be developed that would extend
the test year beyond the date of the proceeding. 636
Conversely, requires no legislation but only a change in sen- , should the PUC staff have questions regarding the length of safety-imposed delays and theproper method of assessing its impact on ratepayers,
the NRC might be in a position to render
637
Further, given the multistate nature ofadvice.
ownership in current nuclear units, PUCs should attempt to better coordinate rate treatment of such
units among themselves'so as to provide a measureof consistency. In sum, all parties would gain from asharing of information and concerns in their different
areas of regulation. The "spillover" effects, after all,affect a matter of mutual concern: a nuclear unit.

10. PUCs and Related Organizations Should
Consider the Long Term Effects on Nuclear Plant
Decisionmaking of Disallowance Arguments

12. FERC Should Improve Its Communication and
Coordination with the NRC

We recommend that PUCs, PUC staffs, and Offices of Consumer Advocates become more sensitive to the impact that their disallowance arguments
have on a nuclear licensee. Looking to long term
effects, they should make challenges to plant costs
only when they seriously believe the utility is attempting unfairly to increase the cost to the customer with no increasing benefit in nuclear safety. To
assist the PUCs themselves in reaching conclusions
on allegations of goldplating, we recommend thatthey fashion a standard of evaluation that asks
whether the challenged expense could be said to beunrelated to safety. I n other words, the burden of
disallowance must clearly rest on the challenger.
Futhermore, to assist PUCs in this area, werecommend that the NRC make witnesses available
to answer the question of safety costs. Rather thanengagein a debate of value-impact or risk assess635
ment,
the NRC witnesses should utilize their expertise only to ask the question posed above:
Could the challenged expense be said to be unrelated to safety?

FERC should also improve its communication
skills. FERC apparently does not coordinate very
well with either State PUCs or the NRC. Because of
its similar economic role with the PUCs, one would
think there would be close contact between the twobodies, but that does not appear to be. This situation leads to different interpretations of the same
Uniform System of Accounts and, at times, conflicti ng rulings. 638
At the same time, because the NRC and FERC
are sister Federal agencies, closer communication
might be imagined than exists. Over the years,
there has been a perception of differences over the
precise distinction in their regulatory functions: the
NRC deals with matters of safety, and FERC withmatters of economic regulation. It scarcely needs
repeating that such a dichotomy ignores the many
forces involved in bringing a nuclear unit into operation as a business component of a utility.' We
recommend that FERC attempt to establish betterli nes of communication between both State PUCs

245

ly, the IRS should attempt to relate the criteria for
placing in service a nuclear unit with standards usedby other regulators (for example, "commercial
operation," "used and useful," and "mode 1 authori-and the NRC when it is regulating a utility with a nuclear unit.
13. FERC Should Eliminate the Threat of
Disallowance of AFUDC that Is Implied in Electric
Plant Instruction 9D

zation").

For example, the author of LTR 7833007 probably recognized the true nature of NRC-mandated
power ascension tests when he ruled that completion of such tests are necessary
before a nuclear
642
unit may be placed in service.
Therefore, a linking of tax treatment and the recommended NRC
certificate of completion of power ascension tests
seem appropriate.

Although we have identified few deficiencies in
the FERC system of regulation as it impacts on nuclear units, one we believe needs rethinking is Elec639
settric Plant Instruction No. 9D. As pointed out,ting a time limit on a test program directly impacts
on nuclear safety and belongs within NRC's authority; not the FERC's. The danger of disallowance associated with Instruction 9D could cause a utility toattempt to minimize a test period that runs greaterthan 120 days. This action could be detrimental tonuclear safety.
We recommend, therefore, that FERC explicitly
eliminate the provision allowing a reduction of
AFUDC in a unit because the test period ran longer
than 120 days. Instruction 9D may continue to seek
i nformation on an extended test program, but should
not contain the threat of disallowance. FERC could
handle allegations of an improperly lengthy test program through the same device as that suggested for
goldplating allegations before the PUCs. That is, an
NRC staff person will testify as to whether the delay
was unnecessary for safety.

Long Term Studies

16. A Study Should Be Conducted into the Relative
Safety of Privately Owned Vs. Publicly Owned
Nuclear Units

Our final recommendations go to two long term
studies that are suggested by our investigation into
this area. The first goes to the basis of thedevelopment of nuclear power: the suggestion thatthe profit motive of investor-owned utilities conflicts
with their commitment to nuclear safety. A numberof people have raised this point after the accident atThree Mile Island and the subsequent allegations
643
Our inthat we have investigated in this report.
vestigation did not focus on this broad question, butsuch a study of the relative safety of public versus
private nuclear units should be considered.
For example, a statistical study of the number ofLicensee Event Reports, violations, and other indications of safety problems could be done for bothi nvestor-owned and public units. If both types ofunits have similar safety records, there would bereason to doubt about the validity of the public
versus private distinction. Numerous other studies inthis area could also be imagined.

14. The IRS Should Require the Use of the Qualified
Progress Expenditures Basis for Recognizing ITC
for Nuclear Units

The final external agency we address is the IRS.
We recommend that the IRS require the use of qualified progress expenditures for all ITCs associatedwith a nuclear unit . Recognition of a utility's expenditures over the period of actual construction(subject to recapture if the unit is not ultimately
placed in service) reduces the impact of placing theunit in service in a certain tax year.

17. A Study Should Be Conducted into theConflicting, Ambiguous Responsibilities of the
Various Regulatory Agencies in This Area

15. The IRS Should Bring Its Standard for
Recognizing a Nuclear Unit into Closer Conformity
with the Standards Used by Other Regulators

Finally, we recommend a broad study into theconflicting and ambiguous regulatory responsibilities
i n this area. As identified in this report, the period ofcompleting and obtaining business recognition of a
nuclear reactor is full of tensions that can force autility to choose one regulator over another.
Perhaps congressional committees would do well toconsider the causes and solutions to this problem.
Otherwise, both utilities and regulators will continue
attempting to reconcile the competing demands of

One advantage in using the qualified progress
expenditures basis is that it eliminates at least a
portion of the uncertainty created by the currently
vague standards of "placed in service" 641 used by
the IRS. We recommend that the IRS consider givi ng greater content to this phrase, as it involves nuclear generating stations, than do current regulations, revenue rulings, and letter rulings. Specifical246

different authorities, all of which ultimately are bestowed by Congress 4

garding financial incentives to complete TMI-2, wehave uncovered a confused system of regulation
where economic considerations and pressuresthreaten the commitment to nuclear safety requiredof licensees. It is our hope that the findings, implications, and recommendations of this section, whenread in connection with the entire report of the Special Inquiry Group, will add to the ultimate improvement of nuclear regulation.

Conclusion
The accident at TMI-2 has the potential to effectdrastic change in the system of regulation of nuclear
powerplants. In investigating allegations made re-247

REFERENCES AND NOTES'Statement of Policy of the NRC (June 13, 1979) at 1.
2
Technically, the term "commercial operation" (or"commercial service"), as more fully discussed below, isthe declaration by a utility that a generating unit is capable of reliably producing power to its customers and isavailable to the associated power pool. Because adeclaration of commercial operation may be a prerequisite to certain regulatory treatment (see note 564 infra
and text accompanying), the term is used in several different ways.
3"1978 Opening Saved Power Company Millions," The
Washington Star, April 5,1979.
4"President Forms Panel to Probe A-Plant Mishap,"
The Washington Post, April 6,1979.
5
Public Citizens, Inc., "Death and Taxes: An Investigation of the Initial Operation of Three Mile Island No. 2,"
mimeographed copy released April 5,1979; see also "TaxPolicy Collides with a Lax Regulatory Policy ... and theResult is the Three Mile Island Nuclear Accident," Caveat
Emptor, April/May issue, 1979.
6
By our definition, "incentives" consist of both positively awarded benefits and the avoidance of detrimental
results.
7
GPU is a utility holding company under the Public Utili ty Holding Company Act of 1934. It is composed of threeoperating utilities: Metropolitan Edison (Met Ed), Pennsylvania Electric Co. (Penelec) and Jersey Central Powerand Light Co. (JCP&L). GPU also includes a subsidiaryservice corporation, General Public Utilities Service Corp.
( GPUSC), which provides technical services to theoperating subsidiaries.
8
See also "1978 Opening Saved Power Company Millions," The Washington Star, April 5, 1979 and Public
Citizens, Inc., "Death and Taxes," mimeograph released
April 5,1979, which similarly suggested such an incentive.
9
l ndeed, there are few States in which utilities are notregulated by some authority. Although we use the term
"PUCs" in this report to refer to such regulators, theseauthorities are known by various titles in different States.
With regard to TMI-2, each of the operating companies
owned a portion of the unit as follows: Met Ed, 50%;Penelec, 25%; and JCP&L, 25%.
10A map of GPU service territories is a part of the
SIG's records.
11
By way of their power interchange and their interconnection with the PJM pool.
12
FERC was formerly the Federal Power Commission(FPC).
13 Penn. Consol. Stat., Chap. 13, Sec. 1307(a) (1966).
14
Penn. Consol. Stat., Chap. 13, Sec. 1308 (1966).
15
Penn. Consol. Stat., Chap. 13, Sec. 1308(d) (66).
16Penn. Consol. Slat., Chap. 13, Sec. 1308(c) (1966).
17

18

21

22

Dieckamp testimony, Pres. Corn. Hearing (May 30,1979) at 50.
23
Failure to obtain prompt regulatory recognition of
O&P expenses could cause a utility to attempt to minimi ze such costs. For example, at TMI-2 there was a cutback in maintenance work around January 1, 1979, 2
days after the plant was declared commercial. Workers
reported that Met Ed officials "told us ... we would beworking a lot less hours on maintenance because they
didn't [yet have] the rate increase"Countdown:
How the Nation's Worst Nuclear Accident Happened,"
Philadelphia Inquirer, April 8,1979.
24
105-06 (Pres. Corn.).
Mr.
Dieckamp dep. at
Dieckamp describes the process as "synchroniz[ing]" thedeclaration of commercial operation and rate relief.
"Relief" need not always be seen as higher rates for thecustomer. If a large baseload (e.g., nuclear) unit replaces
a less efficient and more costly unit, the rise in rate basecharges to the customer may be offset by a lowering infuel adjustment clauses, such that rates remain essentially the same. However, it is relief to the shareholders,
who have capital invested in the project.
25See e.g., Schultz prepared testimony before the
Ohio PUG in 76-1174-EL-AIR; "Declaring a generating unit
to be by test is to gamble with the Company's Earnings."
Id. at 11-12.
26
See e.g., Dieckamp dep. at
107 (Pres. Corn). "Oneof the motivations for [setting forth the commercial operation criteria] ... [was] the absence of definitive criteria on
the books of the FPC [now FERC] that could be used, so
we were attempting to provide a set of ground rules thateveryone could work to."27
See also Arnold dep. at 86.
28
See note 392 infra and text accompanying. GPUSC
was primarily responsible for construction management
and testing of TMI-2. Upon the declaration of commercial
operating, GPUSC turned the unit over to the principal
operating utility, Met Ed.
29
prepared testimony in
PaPUC IDieckamp
79040508 at 2.
30
Letter from W. Kuhns, GPU, to L. J. Carter, PaPUC,
dated August 11, 1978, at 1.
31
1d. at 2.
32
Letter from H. Dieckamp, GPU, to L. J. Carter,
PaPUC, dated July 19, 1978
33Letter from W. Kuhns, GPU, to L. J. Carter, PaPUC,
dated August 11, 1978, at 3.
34 See "Memorandum of Law: Criteria for Determining
When a Nuclear Facility is Used and Useful." Filing of
PaOCA dated October 31, 1978 in PaPUC R-78060626(R.I.D. 626), at 1.
35

Response of Met Ed to the request of Administrative
Law Judge Cohen at N.T.4 (etc.), Met Ed Exhibit no. E21
i n PaPUC R-78060626. (Arnold dep., Exhibit 1114).

penn. Consol. Stat., Chap. 13, Sec. 1308.

Penn. Consol. Slat., Chap. 13, Sec. 1308(c) (1966).

Penn. Consol Stat., Chap. 13, Sec. 1307 (1966). The
complexities and legal arguments concerning the "usedand useful" standard are discussed further, infra at note
564 and text accompanying.
19

20

18 C.F.R., Electric Plant Instruction 3(17).

'*The FSAR itself must include "[p]Ians for preoperational
testing and initial
operations."
10 C.F.R.
50.34b(6)(iii). However, only tests necessary to checksafety systems are required; the licensee may (as did
GPU) schedule additional tests.

18 C.F.R. Part 101.

24 8

PaOCA dated October 31, 1978 in R-78060626 (R.I.D.
Met Ed Exhibit no. E21 in PaPUC R-78060626 at 1626) supra.
(Arnold dep., Exhibit 1114).
38
66
Portions of the TMI-2 total were disputed and, in
Letter from W. Kuhns, GPU, to J. R. Jacobson, Newsome cases, deleted. See discussion infra regarding
Jersey Board of Public Utilities, et al., dated November
main steam relief valves, Touche Ross & Co. report.
30, 1978, at 1.
39
67
PaPUC R.I.D. 626 at 2.
Dieckamp
prepared
testimonyin
PaPUC I68
79040308 at 3. This proceeding took place after the/d. at 59.
69
March 28, 1979 accident.
1n the Matter of the Petitions of Jersey Central
40
Met Ed Exhibit no. E21 in PaPUC R-78060626
Power and Light Company (New Jersey Board of Public
Utility Commissioners), Docket nos. 7610-1021 and 776( Arnold dep., Exhibit 1114).
41
492 (Phase II).
See e.g., Arnold dep. at
83, 86,115, (Herbein dep. at70173-174).
1d. at 3. See also Graham dep. at 8.
42 Graham dep. at 17.
71
1n the Matter of the Petitions of Jersey Central Power
43
and Light Company (New Jersey Board of Public Utility
See Herbein dep. at117. For a discussion as toCommissioners), Docket nos. 7610-1021 and 776-492
whether the NRC requires this link, see note 276 infra(Phase II) at 4.
and text accompanying.
72
441d., Appendix A-1 at 6.
Mark Widoff et al. v. Metropolitan Edison Company,
73
PaPUC R.I.D. 434 at 4 (May 31,1978).
See text accompanying note 10 supra.
45
74
1d. at 5-6.
FERC order of September 28, 1978, Docket no.
46
ER78-494 (Penelec) at 1.
1d. at 5.
47
75
Federal Power Act, Sec. 205(e), 16 U.S.C. 824d(e).
Penelec had sought to decrease its share in TMI-2
78
from 25% to 10% to increase JCP&L's share. This
0f course, the rate went into effect on December 1,
request was denied by the Pennsylvania PUC in another
Following the accidents, intervenors in the
1978.
proceeding (A. 100548) but the 10% figure was used inproceeding noted that TMI-2 had not gone into commerthe pending proceeding (R.I.D. 392) to assess thecial operation until December 30, and hence "it has been
Company's rate base.
unfair for the company to collect the rate at issue here for
48
Hafer testhe first 29 days of December [1978]
See definition infra note 85 and text accompanying.
49
mony
in
Docketno.
ER78-494(postaccident).
ti
Robert C. Humphrey et alt v. Pennsylvania Electric
77
FERC order of January 12, 1979, Docket no. 79-58
Company, PaPUC R.I.D. 392 at 8 (June 8, 1978).
50
MetEd) at 1.
(
1d. at 9.
51
7
S!d. at 3.
1n the Matter of the Petitions of Jersey Central Power
79
FERC order of February 16, 1979, Docket no. ER& Light Company, New Jersey Board of Public Utility
79-112 (JCP&L) at 1.
Commissioners, Docket no. 7610-1021, September 1,
80
1977.
14. at 4.
52
81
1d. at 2.
Portions were disallowed by the FERC at the outset53
on motions for summary disposition. Id. at 2.
14., Appendix A at 1 (unnumbered). New Jersey
82
does allow some CWIP recovery in rate base.
Approximately $150 million of this is from the State
54
PUCs and another $15 million is the automatic increases
Graham dep. at 10-11.
55
allowed by the FPA procedure but subject to refund.
K. C. Springirth v. Pennsylvania Electric Company,
There have been modifications in these increase orders
PaPUC R-78040599 at 1.
as a result of the accident.
66
WI-2 Monthly Operating Report for March, 1978.
83The other major factor was probably taking account
57
K. C. Springirth v. Pennsylvania Electric Company,of rising inflation.
R-78040599
atl.
58
84
Id. at Appendix A. ln 1978, GPU earned a rate of return equity of 10.4%,
59
GPU 1978 Annual Report at 2. The Penelec and Met Ed
14 at 14.
PaPUC orders allowed rates of return on equity of 10.03%
80
Decided May 31, 1978. See note 45 supra and text
and 10.15%, respectively, PaPUC R-78040599 at 24 andaccompanying.
R.I.D. 626 at 44.
85
61
J. F. Romann v. Metropolitan Edison Company,
See PaPUC R.I.D. 392 at 2.
86
PaPUC R.I.D. 626 (decided March 31, 1979). Of course,
But see text accompanying note 628 infra on thethe decision was made before the accident at TMI-2 on
danger of not coordinating future test years and regulaMarch 28, 1979.
tory decisionmaking.
62
87
TMI-2 Monthly Operating Report for June, 1978 (filed
Dieckamp testimony, Pres. Com. (May 30, 1979) at
July 11, 1978). The dramatic slip between this predicted
51
88date and that in the Penelec petition was due primarily to
See text accompanying notes 55-80.
the problems with the main steam relief valves. See text
B9
New Jersey Board of Public Utility Commissioners,
accompanying note 378 infra.
63
Docket nos. 7610-1021 (Phase I), Appendix A at 1.
PaPUC R.I.D. 626 at 2.
64
90This eliminates the "gap" problem previously dis1d. at 1, 5.
65
See text accompanying note 24 supra.
cussed.
"Memorandum of Law: Criteria for Determining
91
See
note 55 supra and text accompanying.
When a Nuclear Facility is Used and Useful," filing of
37

249

92

12

TMI-2 Monthly Operating Report for March 1978.
Discussed infra.
94
Dieckamp testimony, Pres. Corn. (May 30, 1979).
9
AArold dep. at 90.
96
Graham dep. at
12. GPU had been rebuffed previously, it should be recalled, in attempting to include TMI-2
i n rate base outside the test year (See note 50, supra
and text acccompanying).
97
Dieckamp dep. at 66-68.
98
Graham dep. at
14. Graham added: "I don't thinkanyone thought of that strategy any more than they
thought of the strategy of putting it [TMI-2) in service
before December 31 [1978) in order to keep it within thePenelec test year."99
0f course, there were other considerations, discussed infra, which might discourage this approach(regulatory oversight over amount of AFUDC).
100
The decision was actually made on January 11,
1979. PaPUC R-78040599.
101
See note 22 supra and text accompanying.
102
The cost of testing a unit is included in the final
capital cost. 18 C.F.R. Part 101 Electric Plant Instruction
9D.
1 3° 18 C.F.R. Part 101.

oTouche Ross estimated the cost of the delay to be$18-26 million. PaPUC R.I.D. 626 at 16.

Touche Ross report is cited only as an exampleof the danger of arguments for disallowance which confronted Met Ed; GPU challenged the report. See statement of James P. Liberman, GPU General Counsel, in
45-46.
Grahamdep. at122
Brief of PaOCA in PaPUC R.I.D. 626 at 58. However, in neither jurisdiction, apparently, was the argument
accepted. See e.g., PaPUC R.I.D. 626 at 17. See also
121

123

Such a disallowance based on delay had, in fact,
been argued in the TMI-1 proceeding (PaPUC R.I.D. at
170-171) and rejected. Brief of PaOCA in R.I.D. 626 at 71.
See Philadelphia Electric Co., R.I.D. 438 at 20.
124
34.
125Graham dep. at
Dieckamp dep. at
70. See text accompanying note
22 supra.
126
Brief of PaOCA in PaPUC R.I.D. 626 at 88-92. The
PUC ultimately reduced the plant inservice account by$7.8 million.
Decision in PaPUC R.I.D. 626 at 14. The Commission did not find the decision to install Lonergan valves tobe imprudent management but only that the shareholders
should "bear the risk of performance failure."
128
PaPUC R.I.D. 170-171, (Met Ed) 50 PUC 77,102.
129
1ndeed, it has been the consistent position of GPU
officials that TMI-2 was declared in commercial operation
as soon as the criteria it had previously established were
met. It was the end of December before that event
occurred.
130
11.
Graham dep. at131
note 43 supra and text accompanying.
1132
13y "all tests" we are not, of course, suggesting
deletion of those required by the NRC or some otherregulatory body but those tests GPU voluntarily included.
133
See discussion infra, beginning with text accompanying note 290.
134Discussions with Pennsylvania OCA.
135See Brief of PaOCA in PaPUC R.I.D. 626 at 7.
136
117 (doesn't recall discusCompare Arnold dep. atsion of impact of telling PUC it was commercial) with
Dieckamp dep. at
68 ("the kind of thing we would recognize as a factor" to "minimize our vulnerability on thosetechnical arguments").
137 On January 14, the reactor was shut down to repair
leaks on pressurizer instrumentation isolation valves.
Another trip occurred on January 15, 1979. Memoranda
from R. C. Cutler, GPU, to R. C. Arnold, GPU, "Three Mile
Island Nuclear Station Unit 2-Startup Test Program History and Delay Analysis," January 23 and March 13, 1979.
13
BDieckamp dep. at 68.

FERC has the authority to prescribe accounting
procedures for the utilities it regulates. State Commissions (including the PaPUC) use the same system ofaccounts, which in itself was developed by the National
Association of Regulatory Utility Commissions (NARUC).
Holcombe dep. at
46. However, each Commission may
i nterpret the accounting standards differently.
105
18 C.F.R. Part 101, Electric Plant Instruction 9D.
106
Letter from W. M. Donald, FERC to M. Rogovin, SIG,
dated September 11, 1979.
107
FERC "pay[s] very careful attention to the application of AFC .. . [they are] very protective of the asset
values which form the basis for the earning power for thecompanies." Holcombe dep. at 45.
108
1d. at 40-41.
109
1d. at 41-42. The adjustment of the books would
result in a decrease in earnings per share.
11°
TMI-2 Monthly Operating Report for April 1978. See
text accompanying note 378 infra regarding the main
steam relief valves failures.
'"Letter from E. Holcombe, GPU, to L. H. Drennan,
FERC,
dated August 18,1978.
112
Holcombe dep. at
38. In the September 29, 1978
telephone conversation, Morris Fitzgerald told Mr. Holcombe to file a log of problems connected with theextended test period.
n3 Arnold dep. at 119.
114
Holcombe dep. at 44.
104

115

139

1d. at 43.
Letter from W. McDonal d, FERC, to M. Rogovin, SIG,
dated
October 9,1979.
117
Holcombe dep. at 43-44.

See text accompanying note 95 supra.

See Public Citizens, Inc., "Death and Taxes,"
mimeograph released April 5, 1979, at 5.

116

140
141

26 U.S.C. Sec. 38, 46, and 48; and 167, respectively.

116"Review of the Three Mile Island Unit 2 Construction
Project," Touche Ross & Co. October, 1978 (Heward
dep.,
Exhibit 1107).
119
14., conclusions at 6.

142

Surrey, S. S. et al., Federal Income Taxation Vol. 1(The Foundation Press, Mineola, N.Y., 1972), pp.
452-453.

250

143

26 U.S.C. Sec.167(a). Depreciation is also a methodof returning capital to the investor.
144
Most utility commissions take the position that
"regulated utilities are expected to take advantage of allavailable tax deductions. A utility should utilize all available cost-saving opportunities ... in order to keep rates ata reasonable level." Philadelphia Electric Co., PaPUC
R.I.D. 438 at 83.

i n-service date is defined in the tax law, and the determination thereof is totally independent of [the commercial
decision] .... The company has not asked IRS to consider the plant in service on the grounds of this internal
responsibility transfer." Letter from NSP to District Director IRS Exam. Div. Review Staff dated May 19,1979 at 13.
- n3
Letter from J. Kurtz, IRS, to M. Rogovin, SIG, dated
October 4, 1979 at 2. "mhe term 'commercial operation'
is used by regulatory bodies and is not a tax
term ... that ... term is more restrictive than that of theStandards used by the Service as expressed in the regulations and Revenue Rulings for property to be placed inservice."174
Other than Rev. Rul. 79-98.
95
26 U.S.C. Sec.46.
176
26 U.S.C. Sec. 46(d).
77
Use of the qualified progress expenditures requires
an election by the taxpayer. 26 U.S.C. Sec. 46(d)(6).
178
26 C.F.R. Sec. 1.46-(3)(d)(4)(1) allowed ITC "only forthe first taxable year in which such property is placed inservice by the taxpayer."
179
HokCOmbe dep. at 23.
=See IRS Letter Ruling 7833007 (Northern States
Power Company) at 3.
'( "Letter from J. Kurtz, IRS, to M. Rogovin, SIG, dated
October 4,1979.
182
Dieckamp prepared testimony in PaPUC 879080606 (PaPUC) at 4.
153
Letter from NSP to A. L. Woodman, IRS, dated
February 27,1978, at 5.
184
GPU, as are almost all regulated utilities, is a calendar year taxpayer.
185
Hok ombe dep. at 8.
*6/d. at 19-20.
187
Arnold dep. at 110.
188
At this time Holcombe probably was unaware of IRS
Letter Ruling 7833007 (see note 207 infra and text
accompanying). it was also not possible for him to haveseen Rev. Rul. 79-98, because it was published in 1979.
189 Compare Holcombe dep. at. 8-12 (Arnold gives Rev.
Rul. 76-428 but no memo) with Arnold dep. at
109-111.
( Arnold, contacted by telephone, may have seen summary of Rev. Rul., was shown company memorandum as
to whether TMI-2 met criteria.)
19
oFblcombe dep. at 8.
"Again there is confusion as to whether Arnold's
review was a matter which the Directors were interested
in hearing or whether it was a discussion at "sidebar"
between Arnold and Holcombe. Holcombe dep. at 10.
192
14. at 8-9.
193
Rev. Rul. 76-428,1976-2 Cum. Bul. 47.

145

The accelerated methods are those other than thestraight-line method. 26 U.S.C. Sec. 167(b).
146Some commissions also "pass through" the difference between book and tax accounts, as well. See D. S.
Gillmore, "Three Issues in Utility Tax Allowance Determinations," Public Utilities Fortnightly, p. 13 (September I,
1977).
147
26 U.S.C. Sec. 46(f).
148

26 U.S.C. Sec. 46(c)(3).
26 U.S.C. Sec. 46(a)(7).
150
26 U.S.C. Sec. 46(a).
151
26 U.S.C. Sec. 46(c)(1)(A).
152
26 U.S.C. Sec. 167(a).
153
26 C.F.R. Sec.1.46-3(d)(1)(ii).
154
26 C.F.R. Sec. 1.167(a)-10(b). Cf. 26 U.S.C. Sec. 46.
155
26 C.F.R. Sec. 1.167(a)-11(e)(1)(i).
156
Rev. Rul. 76-428,1976-2 Cum. Bul. 47.
157
The nuclear unit discussed in Rev. Rul. 76-428 was
not TMI-2.
1
WThe factual data appears to indicate that the unit
under review was the Trojan Nuclear Plant, owned byPortland General Electric Company and located in Columbia, Oregon.
159
See 26 C.F.R. 1.46-3(d)(I)(ii).
1 0Rev. Rul. 76-428,1976-2 Cum. But 48.
161
Rev. Rul. 79-98, Internal Revenue Bulletin, March 19,
1979. The plant had been constructed under a turnkey
contract. It should be emphasized that Rev. Rul. 79-98
had not been issued at the time GPU was planning its
taxes in 1978.
162
I RS Letter Ruling 7833007 (Northern States Power
Company).
13
26 U.S.C. Sec. 6110(j)(3).
164
1 RS Letter Rutind 7833007 at 1.
*51d. at 2.
*6
1d. at 2-3.
167
Letter from G. S. Pettersen, NSP Controller, to C. D.
Switzer, IRS, dated July 20, 1977.
1sIRS Letter Ruling 7833007 at 5.
169
NSP argued in its protest of the ruling that synchronization is the crucial date because engineers would
never risk either the grid or the generating plant if they
"did not feel certain that the new facility was in fact in acondition of readiness to perform within the grid." Letterfrom NSP to A. L. Woodman, IRS, dated February 27.
149

194

Letter from R. S. Boyd, NRC, to J. Herbein, Met Ed
dated April 7,1979.
195
United Engineers and Constructors was replaced by
Catalytic, Inc. See note 306 infra and text accompanying.

170

IRS Letter Ruling 7833007 (Northern States Power
Company) at 5.
171!. at 4.

196

Rev. Rul. 76-428,1976-2 Cum. Bul. 47.
Final Safety Analysis Report (FSAR), Three Mile
Island-Unit 2, Vol. 9, Sec. 14.1.3.2.
198
Memoranda from R. C. Cutler, GPU, to R. C. Arnold,
GPU, "Three Mile Island Nuclear Station Unit 2-Startup
197

172

The position of NSP in its protest is that the date ofoperation "is entirely irrelevant to the question of whether
the plant is or is not in service for tax purposes. The tax

25 1

226

Test Program History and Delay Analysis," January 23
and March 13, 1979. Some preoperational tests were,
however, conducted after fuel load at TMI-2. Toole dep.
at 28.
Final Safety Analysis Report (FSAR), "Three Mile
Island-Unit 2," Vol. 9, Sec. 14.1.4.
20oMemoranda from R. C. Cutler, GPU, to R. C. Arnold,
GPU, January 23 and March 13, 1979.
201
December 17 is the date of the GPUS Board Meeting. As is discussed below, doubts as to that conclusion
might have been equally reasonable later in the month.
202
There is some dispute as to exactly what tests
GPU should have run as part of the power ascension test
program. See text accompanying notes 341-357 infra.
We have used GPU's own declaration date for simplicity.
203
Rev. Rul. 76-428,1976-2 Cum. But 47, 48.
204
Rev. Rul. 79-98, See discussion supra.
205
1RS Letter Ruling 7833007, supra.
208
11 i s interesting to speculate as to whether one of
the tests postponed or deleted had decreased the possibility of finding a deficiency. But it would be disingenuous
to suggest that the possibility of such a discovery and its
i mpact on tax planning was the reason for the deletion.

See Dieckamp dep. at 108 (Pres. Com.).
See Public Citizens, Inc., "Death and Taxes,"
mimeograph released April 5, 1979, at 5.
228
The only major construction ongoing at the start of1979 was the Forked River Nuclear Unit. GPU does,
however, generate a large portion of its funds (59%GPU 1978 Annual Report at 10) from internal sources. A
reduction in tax advantages (ITC carryback, 1/2-year convention) might have impacted upon the company's continuing ability to finance such a large portion from within.
See Public Citizens, Inc., "Death and Taxes," mimeographreleased April 5, 1979 at 6-7.
Presuming an interest rate of 10%, the calculation
would be 0.10 x $29 million = $2.9 million.
23°Dieckamp dep. at 71.
231"Pennsylvania-New Jersey-Maryland Interconnection, 1976" at 3.
232Id. at 5.
233
See Article 4.1 of the Pennsylvania-New JerseyMaryland Interconnection Agreement for a listing ofmembers' responsibilities to coordinate planning andoperation of bulk power facilities.
234
Pennsylvania-New Jersey-Maryland Interconnection Agreement, Article 6.1.
227

207

Mr. Daley reported to Mr. Holcombe. Holcombe
dep. at 13.

Id., Schedule 2.01(b).
Id., Schedule 2.01(d).
237
Pennsylvania-New Jersey-Maryland Interconnection238
Agreement Supplemental Agreement, Schedule 4.01.
Letter (with attachments) from J. D. Gassert, GPU,
to D. J. Evans, SIG, dated December 3, 1979.
239
The rate effective June I, 1979 was $25.55 perkilowatt as shown in Schedule 4.01 of the PJM Agreement, Rev. no. 2, dated March 15, 1979. If TMI-2 wastaken out of GPU's "installed capacity" a charge would beassessed on this rate since GPU would be under theirforecast obligation. However, TMI-2 is currently considered as installed capacity but on 100% forced outage.
240
PJM Agreement, Article 1.1(f).
241
PJM Agreement, Schedule 2.211(b).
242Report of Touche, Ross & Co., October 1978,(Reward dep., Exhibit 1107) conclusions at 2.
235

208

Memorandum from P. F. Daley and J. R. Thren,GPU, to V. H. Condon, et al., GPU, "Status of TMI No. 2
for Income Tax Purposes," December 28, 1978,
209The reference is to the main steam relief valve
failure growing out of an April 23, 1978 transient. Seenote
378 infra and text accompanying.
210
Memoranda from R. C. Cutler, GPU, to R. C. Arnold,
GPU, "Three Mile Island Nuclear Station Unit 2-Startup
Test Program History and Data Analysis," January 23 andMarch 13, 1979.
211
Holcombe dep. at 15.
2121d. at 16-17.
2131d. at 17-18.
2 14.
d at 17, 20.
215
Id. at 6.
218
14. at 7.
217
GPU files a consolidated tax return for the corporation and all subsidiaries. GPU 1978 Annual Report at 24.
218
Analysis prepared by GPU Comptroller E. Holcombe, GPU, (Holcombe dep., Exhibit 1110) at 3.
21
e26 U.S.C. Sec. 46(e).
22oAnalysis prepared by E. Holcombe, GPU, (Holcombe dep., Exhibit 1110) at 3.
221
14. The credits are discussed supra.
222
Primarily, this reduction was due to the ITC anddepreciation deductions discussed supra.
223
GPU 1978 Annual Report at 16.

238

244JMe 2M at A-I.

19,1 um from R.C. Arnold, GPU, to T.L. Carroll, Jr., Ju
July
1979.
245
Letter from J. D. Gassed, GPUSC., to D. J. Evans,
SIG, December 3,1979.
248
Summary of interview with R. H. Simms, September
6, 1979.
247
Summary of telephone conversation between D. J.
Evans and J. D. Gassert, November 29,1979.
GPU 1978 Forecast, (Graham dep., Exhibit 1115)
GPUPlanning Department.
Summary of telephone conversation between D. J.
Evans and J. D. Gassert, November 29, 1979; see letterfrom J. D. Gassert, GPU, to D. J. Evans dated December
3,1979.
250
Schultz prepared testimony before the Ohio PUC in
76-1174-EL-AIR.
251
Forced outages for units in service less than 1
calendar year may not affect the capacity requirement ofa PJM member. See PJM Agreement Schedule 2.212(e),224

26 C.F.R. 1.167(a)11(c)(2)(ii). The modified half-year
convention states that if a unit is "placed in service" in thesecond half of a tax year, it is allowed depreciation for
one-half of the year. As in the case of TMI-2, which wasplaced in service some time in the fall of 1978, this canamount to a significant difference.
225

Analysis prepared by E. Holcombe, GPU, (Holcombe dep., Exhibit 1110) at 2.

252

(f) and (g). This increases future forecast obligations.
See PJM Schedule 2.21 (showing the formula for calculati ng a member's forecast obligation).
252
Herbein dep. at 118.
253 Arnold dep. at 118.
254
Dieckamp dep. at 104 (Pres. Com.).
255 Statistical information attached to letter from GPU
Service Corp. to Standard & Poor's Corp., dated October
20,1978.
256
Met Ed form 10-K (SEC) for fiscal year ended
December 31, 1978 at 3.
257See discussion supra, beginning with text accompanying note 8.
258

Met Ed form 10-K (SEC) for fiscal year ended
December 31, 1978 at 4.
259
Graham dep. at
260

37.
1d. at 37-38.
281
Letter from J. B. Liberman to L. Vandenberg, SIG,
dated October 5, 1979.
262
1n the Matter of Public Service Company of New
Hampshire, Seabrook Station Units 1 and 2, CU-78-1, 7
NRC263
1, 14.
Moody's Bond Surveys, January 9, May 29, andSeptember 4, 1978.
264
From AA to A.
265"Lower Bond Rating Troubles Lilco," New YorkTimes, August 20, 1979.
266 Summary of telephone conversation between L.
Vandenberg
and B. Burke, Moody's, Inc., July 19, 1979.
267
Summary of telephone conversation between L.,
Vandenberg and T. Fendrick, Standard & Poors, July 17,
1979.
268 Summary of telephone conversation between L.
Vandenberg and P. Jadrosick, Moody's, Inc., July 17,
1979.
269 Graham dep. at 31.
2701d. at 37.
271

GPU 1978 Annual Report at 2.
272 See Met Ed Annual Report 1978 at 20.
273
Graham dep. at 21.
274 Arnold dep. at 113.
275
See GPU 1978 Annual Report at 20.
276
Dieckamp prepared testimony in PaPUC I79040308 at 1.
277
NRC Regulatory Guide 1.68 at I (footnote).
278
NRC Regulatory Guide 1.68 at 3.
279
NRC Regulatory Guide 1.68 at 3.
280 Standard Review Plan at 14.2-5(a) and (b),reprinted as Acceptance Criteria #10 in Revision 1, issued
January 1979.
281
NRC Regulatory Guide 1.68, Sec. C.5, at page 1.684.
282 Inspection and Enforcement Manual, Chap. 2514 at
2514-11 April 1, 1978.
283
Kellogg dep. at 48-51.
284 Inspection and Enforcement Manual, Chap. 2514 at
2514-10, April 1, 1978.
285
Final Safety Analysis Report (FSAR), Sec. 14.1.4.
286b., Sec. 14.1.4(d).

25 3

287
Dieckamp dep. at
288

58.
Final Safety Analysis Report (FSAR), Three MileI sland-Unit 2, Vol. 9, Fig. 14.1-1, "Test Program
Schedule," (October 8, 1975).
289
ki., Sec. 14.1.4(d).
29°GPU began planning for two nuclear units at TMIback in the mid-1960s as environmental factors madecoal look less attractive. Summary of telephone conversation between D.J. Evans, SIG. and Conrad Six, PaPuc,
July 11, 1979.
2'The commercial operation date of TMI-2 was set as
May 30, 1978 in Monthly Operating Reports filed with the
NRC up to the May 1978 report (filed June 15, 1978),which
set a September 1, 1978 date.
292
TMI-2 Monthly Operating Report for November
1978 (filed December 15, 1978). See also Arnold dep. at 123.
293

That occurred on April 23, 1978 when the main
steam relief valves malfunctioned and, subsequently, GPUdetermined that these valves would need to be replaced.
See294note 378 supra and text accompanying.
Kellogg dep. at 13.
295 See also Varga dep. (August 15, 1978) at 12. Nagle
dep. at 41.

42 U.S.C. Sec. 2235. Inspection and Enforcement
writes a letter to NRR, commonly called a 94-300 letter(after the applicable IE manual procedure module) statingthat all necessary construction is complete and issuanceof an OL is proper. NRR (and Atomic Safety and Licensi ng Boards) are required to find that the plant was constructed in conformance with its construction permit (CP).
10
C.F.R.
Sec.
50.57(a)(1).
Some
additional"construction"-generally of a "finishing" nature-is conducted after the operating license (OL) is granted. See
I nspection and Enforcement Manual, Chap. 2513 at
2513-3 (February 28, 1975.)
297
Again, GPU apparently was not concerned with a
December 31, 1978 date until November 1978. The OL
was obtained on February 8, 1978. There may have beenother incentives for an OL rush, such as the need for a
May 31 commercial operation date for PJM Pool purposes. See note 231 supra and text accompanying.
However, we did not examine that question.
298 Kellogg dep. at 11.
299
1 E I nspection Report 50-320/77-32.
300
Kellogg dep. at 12.
"Id. at 10.
302 The test involved addition of lithium to the reactor.
Under the test procedure, GPU should not have gone to ahigher temperature until checking to see where the lithium
had been distributed. However, the test engineer did not
sample for the lithium until after exceeding the specified
temperature. Kellogg dep. at 24.
3031E Inspection Report 50-320177-32.
304
Kellogg dep. at 24.
305
Kellogg dep. at 11.
308
Nagle dep. at 10.
307 Catalytic did, however, assume responsibility forremaining construction. While UE&C test engineers
remained at the site under a separate contract, the craft
labor answered to Catalytic.
306
Heward dep. at 14-15.
296

ONagle dep. at 12-13.
For example, Baltimore Gas & Electric reportedlyused a similar procedure at its Calvert Cliffs station.
311
Kelbgg dep. at 34.
3t2
Nagle dep. at
12. UE&C was informed of the shift
around August 1976. The change occurred in June 1977.
See Heward dep. at 15.
3t3
Heward dep. at 16-17.
Kellogg dep. at 34.
I nterviews with Catalytic, Inc. management.
31
BKellogg dep. at 34.
3
nNagle dep. at
14. Nagle estimated that TMI-2 was
90-95% complete. Heward dep. at 14.
318
Ar oId dep. at 104.
3*
Heward dep. at 15.
17. Mr. Kellogg said the list was
Kellogg dep. at"several thousand" diems contained in three, 3-inch
volumes. By comparison, he said, "[i]t was a larger
number than I had been previously exposed to at otherprograms of that type."321/d. at 18.
322
Report of Touche, Ross, and Co., October 1978,(Heward dep., Exhibit 1107) conclusions at 4.
323
See note 118 Supra and text accompanying
324
Nagle dep. at 21.

Opening Saved Power Company Millions," of April 5,
1979.
335And also transmitted to the New Jersey GPU.
MSee note 26 supra and accompanying text.
337
There is some suggestion that a combination of
FERC and NRC requirements assist in making completionof power ascension tests a prerequisite to commercial
operation. See text accompanying note 276.
3381S Letter Ruling 7833007 so suggested. Thisi nformation was available to top GPU officials in late
December 1978. See text accompanying note 276.
339
Toole dep. at 17.
34 °Meeting the May 31, 1978 PJM Pool date might
have been difficult, as GPU apparently realized in postponing the inservice date in March to June 30, 1978.
Memorandum from R.C. Arnold, GPU, to T.L Carroll,GPU, supra.
341
10 C.F.R. Sec. 50.34(b)(6)(iii).
342
See Regulatory Guides 1.68,1.70.
343
Babcock & Wilcox proposed tests are contained,
for example, in Babcock & Wilcox "Standard Nuclear
Steam System," B-SAR-205 at Vol. 3,14-i.
34°10 C.F.R. Sec. 50.34.
346
Summary of telephone conversation between D.
Evans and J. Barton, GPU, November 26,1979.
Final Safety Analysis Report, "Three Mile Island
Nuclear Station-Unit 2," Vol. 9, Chap. 14.
347 See discussion regarding this meeting, note 400
infra and text accompanying.
348
GPUS, Commercial Operation Review Board
Report, October 26, 1978 (Reward dep., Exhibit 1109) at
4. Presumably, the reference to "Federal requirements"
means the tests were not required by 10 C.F.R. Sec.
50.34.
34
e'roole dep. at 29.
350
1d. at 29-30.
351
Heward dep. 20, 22-23. But compare
To ledep.at30.(NoreviewinSeptember-December1978time
period).
3 2
Heward dep. at 20.
353 Summary of telephone conversation between D.
Evans, SIG, and J. Barton, December 4,1979.
35 4' Memoranda from R. C. Cutler, GPU, to R. C. Arnold,
GPU, January 23 and March 13,1979, supra.
365
Arnold dep. at 123.
356
The schedule had already slipped 6 months overall
at that point.
357
The test procedures in the FSAR were drafted asl ate as December 1975. TMI-1 went into commercial
operation September 2,1974.
358
Final Safety Analysis Report, "Three Mile Island
Nuclear Station-Unit 2," Vol. 9, at 14A-90,14.1-5.
35
OSse e.g., Jersey Central Power and Light, TP
800/21, "Power Escalation Test Sequence, Three Mile
Island Nuclear Station Unit No. 2."

30

31O

32

r'The issue was discussed in a TMI-2 prehearing
conference on January 28, 1977. Transcript at 137. See
discussion of "financial qualification" and recommended
changes. Note 595 infra and text accompanying.
326
Babcock & Wilcox was the nuclear steam supply
system (NSSS) vendor at TMI-2.
327
Spangler dep. at 36-37.
32
aSpangler dep., Exhibit 1151.
329
GPU had predicted initial criticality on March 25,
1978. Monthly Operating Report for February 1978 (filed
March 13, 1978). It would take approximately a month toload fuel and reach that point.
33% could be argued that the advantage of having alarge baseload unit producing cheap, nuclear baseload
energy is sufficient incentive for all utilities to complete a
unit as soon as possible.
"See e.g., discussion of PJM pool incentives, note
242 supra and text accompanying.
332

intemai GPU correspondence indicate that thecommercial operation date was changed in March 1978
(before the April 23 transient). But that change was fromMay 31 to June 30,1978. Following the April 23 transientthe date was further postponed in late June to October
31, 1978. Memorandum from R. C. Arnold to T. L. Carroll,March 29,1979 (July 19, 1979). Further postponements inthe predicted commercial operation date are shown in
GPU TMI-2 Monthly Operating Reports as follows:
December 1, 1978 (October report); December 31, 1978
(November report). See also Arnold dep. at 123.
333
GPU would contend, in fact, that this thought did
not occur until early December 1978. Arnold dep. at 123.

3BO
See e.g., Memorandum from T. Faulkner, GPU, to R.
Toole, GPU, (TMI-H-6765) June 29,1978, at 4.

334 April 23, 1978 through December 30, 1978. This
point seems to have been implicitly recognized by anumber of people. See e.g., former Pennsylvania Consumer Advocate Mark Widoff in The Washington Star "1978381
The "unit acceptance test" is apparently also known
as the "initial warranty run." Reward dep. at
18-19; Cf.
Spangler dep. at 16.

25 4

382
Final Safety Analysis Report, "Three Mile Island
Nuclear Station-Unit 2," Vol. 9, at 14A-90.
363
Amold dep. at 120.
Summary of telephone conversation between D.
Evans and J. Barton, December 4, 1979. Apparently it iscommon for NSSS vendors to include such acceptancetests in their supply contracts. See e.g., contract
between General Electric and Commonwealth Edison for
Carroll County Units at VIII-3, VIII-5. The purpose of sucha clause is to set a definitive date beyond which acceptance of the unit will be deemed to have occurred. The
unit acceptance test is not required to be included in the
FSAR by Regulatory Guide 1.68.
365
Babcock & Wilcox "Standard Nuclear Steam System," B-SAR-205 at 14.1-8.1-8.
366
Arnokf dep. at 120.

B&W notified GPU in November 1978 that it considered TMI-2 to be ready for the unit acceptance test.
By terms of the contract, GPU had 90 days to run thetest, which it did in February, 1979. Summary of telephone conversation between D. Evans and J. Barton,
December 4, 1979.
368
GPUSC job description of TMI Project Manager.
( Heward dep., Exhibit 1108) at 2.
369
Heward dep. at 20.
370.
at 18.
371
Spangler dep. at 17.
372
The test is for this reason sometimes known as the
100-hour warranty test, for it follows, in theory, 100 hoursof full-power operation.
373
Heward dep. at 19.
374
There is some debate as to whether a utility mustobtain NRC approval for a change in an FSAR. See 10
C.F.R. Sec. 50.59 (c).
375
See note 41 supra and text accompanying.
370
GPU officials did, however, clear their decision to
postpone the test with NRC Project Inspector Donald
Haverkamp, who presented no objections. Summary of
telephone conversation between D. Evans and J. Burton,
December 4,1979.
367

377

100 hours of operation.
Letter from E. 'Holcombe, GPU, to L. H. Drennan,
Jr., FERC, dated August 18,1978. (Attachment).
379k1.
at 2.
sO
As William Spangler of B&W wrote in 1978 internal
B&W paper: "... because of the dollar investment,
reducing downtime during the test period is just as important to the operating utility as it is in follow-up operating
years." (Spangler dep., Exhibit 1151) at 3.
June 27, 1978 letter from GPU Service Corp. Contracts Dept.
382
See Holcombe letter from E. Holcombe, GPU, to L.
H. Drennan, Jr., FERC, dated August 18,1978, supra.
Arnold stated that "We started fairly shortly after
the incident to do the engineering and procurement activities necessary to change the valves." Arnold dep. at
133,
134,
Letter from E. Holcombe, GPU, to L. H. Drennan,
Jr., FERC, dated August 18,1978.
Arnold dep. at 135.
3
w/d. at 134.
378

Letter from E. Holcombe, GPU, to L H. Drennan,
Jr., FERC, dated August 18, 1978.
Memoranda from R. C. Cutler, GPU, to R. C. Arnold,
GPU, January 23 and March 13, 1979.
389
Haverkamp dep. at 94.
'°1d. at 94-95.
391
Haverkamp dep. at 96.
392As discussed below, some utility commissions
equate commercial operation with "used and useful"status. See notes 565 and 566 infra and text accompanying.
See note 22, supra and text accompanying.
Another aspect of this risk has to do with the intracorporate relationships at GPU. Dieckamp said he wasi nterested in assuring the operating companies (Met Ed,
Penelec and JCPSL) that the unit the GPUSC startup
team was turning over to them was truly ready for commercial operation. Dieckamp dep. at 115 (Pres. Corn.).
394
Amold dep. at 78.
395
Dieckamp said the concept of this formulation
probably grew out of his past experience in the space
program where such formal turnovers were common.
Dieckamp dep. at 117-118 (Pres. Corn.).
John Bachofer was the principal GPUSC individual
who drafted the procedures.
387

397

GPU Service Corporation Manual at 301-305,
i ncluded in "Determination of Technical and Organizational Readiness for Placing Three Mile Island Unit 2 into
Commercial Operation," October 26, 1978 (Herbein dep.,
GTF Exhibit 13).

3
ftieckamp dep. at 116 (Pres. Corn.). Actually, a draftof the GPUSC procedure was used.
398
GPU Service Corporation Manual, Sec. 3.2(included in Herbein dep., GTF Exhibit 13).
400
GPUS, Commercial Operation Review Board
Report, October 26,1978 (Reward dep., Exhibit 1109) at 1.
401
This material is contained in "Determination ofTechnical and Organizational Readiness for Placing Three
Mile Island Unit II into Commercial Operation," October
26,1978 (Herbein dep., GTF Exhibit 13.)
402
GPUS, Commercial Operation Review Board
Report, October 26, 1978 (Heward dep., Exhibit 1109),
Sec. 1.2 at 1.
°03
Amold dep. at 95.
404
GPUS, Commercial Operation Review Board
Report, October 26, 1978 (Reward dep., Exhibit 1109),
Sec. 2.0 at 1.

406
Among the outstanding items were "Test Completion" and "NSSS vs. Turbine Generator Capability."
GPUS, Commercial Operation Review Board Report,
October 26, 1978 (Heward dep., Exhibit 1109), Sec. 5.0 at
6.
406
1d. at 4.
407
There is some confusion as to how members of the
CORB could sign off on the conclusion stated above
when such an important item as the test program had notbeen completed. Apparently, the signatures do not certify the plant as being ready for commercial operation at
the moment of signing by the CORB members (December
18 to December 26, 1978). That required the report ofthe subcommittee on the open items. Rather, members
were stating that, based on the information they had seen

25 5

at that point, "that they had no information at that time
which was the basis for not proceeding to place the unit
i n commercial operation, once its test program had been
completed." (Arnold dep. at100; See generally Id. at
97-101).
See Arnold dep. at 100-101.
Mr. Miller participated, as specified in the GPUSC
Procedure, because it was felt the station manager
should have input into the readiness of the unit for commercial operation. Herbein dep. at131. Mr. Miller did, infact, contribute. GPUS, Commercial Operation Review
Board Report, October 26, 1978 (Heward dep., Exhibit1109) at 6.
410
103
4 Arnold dep. at'Herbein dep. at 129.
412Memoranda from R. C. Cutler, GPU, to R. C. Arnold,
GPU, January 23 and March 13, 1979, supra. GPU
declared the power ascension test program completewith the successful running of the full-power generator
trip test on December 28, 1978.
413

GPUS, Commercial Operation Review Board Report,
October 26, 1978 (Heward dep., Exhibit 1109), Supplement
A (CORB Subcommittee Report) at 1.
414
GPUS, Commercial Operation Review Board Report,
October 26, 1978 (Heward dep., Exhibit 1109), Supplement A, (CORB Subcommittee Report) at 2. R. Arnold,
W. H. Hirst and R. F. Wilson signed the CORB Subcommittee
Report.
415
Arnold dep. at 129-130.
41
OHerbein dep. at 132.
417
Dieckamp dep. at 117 (Pres. Com.).
418
Arnold dep. at 74-75.
419See Id. at 102.
42°See text accompanying note 456 infra
regarding
Mr. Arnold's knowledge of the financial consequences ofgoing into commercial operation in 1978.
421
See discussion of incentives, supra.

422 One of the reasons for the establishment of a
CORB and the formalization of the commercial operation
decisionmaking appears to have been the perceived needon the part of GPU to document the prudence of bringing
the plant into commercial operation. See Arnold dep. at
80.

separate contract from the construction agreement.
Nagel dep. at 43-44, 49.
10 C.F.R. Sec. 55.3 et seq.
Herbein dep. at 138.
434
Haverkamp dep. at 101-102.
435
Arnold dep. at 121.
438
Haverkamp dep. at 102.
437
Kellogg dep. at 11.
438
Toole dep. at 14.
432
433

439
GPU had a contract with B&W to provide startup
services at TMI-2. Spanger dep. at 6.

440W. H. Spangler, "Startup Service and Training
Activities During 1977", (prepared for internal B&W
management meeting) (Spangler dep., Exhibit 1151) at 29(Fig. 6).

"Apparently TMI-2 had just loaded fuel when thisreport was written. The other units compared were:
Oconee 1 and 2, TMI-1, Arkansas Nuclear One-1, Oconee
3, Rancho
Seco, Crystal River and Davis Besse 1.
442
Memoranda from R. C. Cutler, GPU, to R. C. Arnold,
GPU, January 23 and March 13,1977, supra.
443
Without the unit acceptance test.
444
Schultz prepared testimony before the Ohio PUC in
76-1174-EL-AIR at 11.
445
While there is wide variety on this criterion, it would
seem to be prudent management to complete the test
program before exposing the shareholders to any risk, Id.
at 11-12.
44O
TMI-2 Monthly Operating Reports for March andDecember, 1978, respectively.
447
Obviously we are not dealing with precise numbers
here. Because each nuclear unit has its own problems, acomparison of schedules can never be a precise indicatorof the "average" time.
448
See also Haverkamp dep. at 93.
449"3 Mile Island Workers Talk of 'Rush Job,'" Philadeiphia Inquirer, April 16,1979.
450
451

•

For example, the article quoted a subordinate ofJack Herbein as hearing Herbein say, "A lot of times you
have to take shortcuts to get back on line." Herbein does
not recall making such a statement. Herbein dep. at136-137.
452
Richard Blakeman did, however, repeat his assertion in the article that tests on the snubbers in Unit 2 hadbeen "passed with a magic pencil," a euphemism for "faki ng" the tests. Summary of telephone conversation
between L. Vandenberg and R. Blakeman, Met Ed, September 18, 1979.
453
Haverkamp dep. at 90.
454
See e.g. Herbein dep. at 145.
455
NRC did investigate allegations made during theconstruction of Unit 2 that improper welding had takenplace. Eventually, the improper welds were discovered
and corrected. See Narrow dep. at 18-21.
45
See discussion of incentives supra.

423

lnformal discussion with Met Ed or GPU employees.
Because of the nature of these assertions, we have not
identified the sources. See Heward dep. at 38.
424
See note 43 supra and text accompanying.
425
Representations were made to the Pennsylvania
PUC that the FSAR power ascension test program would
be completed before TMI-2 was declared in commercial
operation. See note 42 supra and text accompanying.
426
See IRS Letter Ruling 7833007, supra.
427See note 358 supra and text accompanying.
428
Final Safety Analysis Report (FSAR), "Three Mile
Island-Unit 2," Vol. 9, at Fig. 14.1-1
4~Herbein dep. at 133-134.
4
Toole dep. at 5.
431
Other test engineers assisted the 10 GPU employees involved in the test program. For example, there
were 30 to 35 UE&C test engineers present under a457 Forexample, utility management might simply
desire to bring to a completion a long term project.
458

256

See note 188 supra and text accompanying.

utility business that top operations personnel are involved
i n rate proceedings and consult with management on
finance-related questions. Our recognition of this "nexus"
does
not indicate fault, it is simply a recognition of reality.
492
Arnold dep. at 137.
493We have postulated that this was the motivating
force but, as noted previously, there are alternate explanations. See note 352 supra and text accompanying.
494
As Norman Mosley of IE said: "... these motivations to hurry are already there, with, or without [concern
with the date of commercial operation]." Mosely dep. at
215.
495
ld at 214.
496
See
note 6 supra and text accompanying.
497
See text accompanying note 8, supra.
498
See text accompanying note 290, supra.
499
See text accompanying note 535, infra.
500
The "cause" of the TMI-2 March 28, 1979 accident
has been addressed by several reports, which should be
consulted for a complete analysis. "Investigation into the
March 28, 1979 Three Mile Island Accident" by Office ofI nspection and Enforcement, Investigative Report 50320/79-10 (NUREG-0600); "Report of the President's
Commission on the Accident at Three Mile Island,"
October 31, 1979. See also other sections of this Special
I nquiry Group report.
50'Compare Public Citizens, Inc., "Death and Taxes,"
mimeograph released April 5, 1979 at 3: "...the haunting
question remains: Could the March 28, 1979 accident
have been prevented by a rational utility tax system andnuclear regulatory structure."502
42 U.S.C. Sec. 2133(d).
503
10 C.F.R. Sec. 50.40(a).
5°4
10 C.F.R. Sec. 50.40(c).
505Obviously to determine what would be "inimical
to ... health and safety," the commission must understandwhat
is "safe."506
See discussion in this SIG report dealing with theregulatory system.
50710 C.F.R. Sec. 50.100.
508
There is a range of IE action which can be taken insuch instances. See Inspection and Enforcement Manual,
Chap.
0800.
509
There is such authority under 10 C.F.R. Sec.
50.100.

459

This was not unusual. As an officer of the Corporation, Arnold usually attended meetings. The meeting
took place on December 17, 1978.
460
Holcombe dep. at 8.
4611d. at 19.
462
Arnold dep. at 109.
483
Id. at 109, 110.
464
Holcombe dep. at 15.
465 See Dieckamp dep. at 52-54.
4"
See note 189 supra.
487
Arnold dep. at 109.
46
Dieckamp dep. at 53.
469
As will be recalled, Rev. Rul. 76-428 permitted
recognition of a unit which had shutdown "due to anabundance of hydroelectrically generated power" not"because of any defect in the system." See Rev. Rul. 7998. 70
a Arnold dep. at 109. As previously discussed, thesteam valve failure was probably the type of deficiency
that would cause the IRS to conclude that the unit had
not "operated without failure." See Rev. Rul. 79-98.
471
Arnold dep. at 86-90.
472 The company's memorandum, it will be recalled,
was a copy of FSAR, chapter 14. See note 37 supra andtext accompanying.
473
Despite the existence of the CORB, Arnold has
acknowledged that he had the final responsibility for
TMI-2 going into commercial operation. Arnold dep. at
101-102.
474
1d. at 122.
475
Herbein dep. at 119.
476
1-earned through informal discussions with past Met
Ed-GPU employees. It should be noted, however, thatthe specificity of knowledge drops off at lower levels.
Further, some employees insist they did not know of any
financial incentives associated with a 1978 deadline. Seee.g., Heward dep. at 4.
an
The architect-engineer.
478
Cobeandep. at 157-159 (Pres. Com.).
479
nterview
with Catalytic, Inc., September 13, 1979.
l46°
Cobeandep.
at 157 (Pres. Com.).
4 1
s Arnold dep. at 112.
482 Id. Declaring a unit complete at something lessthan 100% power was provided for in the commercial
operation procedures.
483
Dieckamp dep. at 59.
481
See e.g., Herbein dep. at 135.
Arnold dep. at 112.
4a
Id. at 113.
487
Dieckamp dep. at 60.

51

D1n the matter of Maine Yankee Atomic Power Company (Maine Yankee Atomic Power Station), ALAB-161, 6

AEC
1003, 1009 (1973).
511
Construction permit, CPPR-66, issued November 4,
1969.
512 Memorandum from H. Thornburg to S. Boyd, January 27, 1978.
513
See note 296 supra and text accompanying.
514M the Matter of Metropolitan Edison Company, etal., (Three Mile Island Nuclear Station, Unit No. 2), LBP77-70,6 NRC 1185 (1977).
515
NRC Facility Operating License No. DPR-73 (TMI2), Feburary 8,1979.
516
Eisenhut dep. at 32 (Pres. Com.).

4s

See Philadelphia Electric versus Westinghouse
Electric Corp., 1964-Trade Cases, para. 71,123 (E.D. PA.

1964).
4
asSee Arnold dep. at 113.
490
Arnoid dep. at 113.
491
This intermingling of business and operating concerns is not unique to GPU. Rather, it is common in the257

5'In total, some 40 IE inspectors were involved in
TMI-2 inspections in 1978. (List prepared by Bruce Grier,
IE Region 1 Director, August 16,1979.)
5* The testing program was subjected to some scrutiny. See IE Inspection Reports 78-32, 78-39, See also
Toole dep. at 32.
5*IE inspectors observed a number of major startup
tests. Haverkamp dep. at 88-89.
2
S ONRC, Amendment No. 6 to DPR-73 (August 17,1978). In fact, the NRC Staff's Safety Evaluation Reportfound the replacement valves to be more effective.
Safety Evaluation Report at 7-8.
5
10 C.F.R. Sec. 50.91; See 10 C.F.R. Sec. 50.40(a).
522NRC, Amendment No. 1, License No. DPR-73.
( March 3, 1978). The amendment allowed hydrostatic
testing before criticality, "(1) in the interest of minimizing
delays... " Safety Evaluation Report at 1. Cf. Varga dep.
(August 15, 1979) at 21-23.
523
NRC, "Notice of Granting of Relief from ASME Section XI Inservice Inspection (Testing) Requirements" (April
21,1978).
524
See 10 C.F.R. Sec. 50.55a(g)(6)(i).
525
10 C.F.R. Sec. 50.55a(g)(6)(i).
26
S See e.g., letter from R. S. Boyd, to J. G. Herbein,
dated March 10, 1978, authorizing proceeding to mode 4(hot shutdown). See also letter from J. Sniezek to D.
Vassallo, dated March 24, 1978, stating that the OL conditions necessary before' mode 2 authorization "havebeen resolved to the satisfaction of E."
527
Washington Star ("1978 Opening Saved Power
Company Millions") April 5, 1979, stated that "four eventsat reactor No. 2 that could be labeled as 'reportable' took
place between December 13 and December 26, 1978 thatwere reported in 1979." However, LER nos. 78-72, 7873, 78-74 were reported in accordance with the 30-day
reporting rule since they were not of immediate concern.
There is no reason for believing that the NRC would havetaken some action against Met Ed before the end of 1978
had it known of these events.
528
Varga dep. (August 15,1979) at 12.
See discussion elsewhere in this SIG report
regarding the regulatory system. See also Haas dep. at
91, 98-100 (quality assurance review of applicant's proposed startup test program).
53°Afthough it might decrease this possibility, even a
resident inspector program will not eliminate such action.
53t
The penalties for failing to report a reportable event,per the technical specifications, is potential loss of thelicense or lesser fines. 10 C.F.R. Sec. 50.71; 10 C.F.R.
Sec. 50.100.
532
See NRC "Reactor Safety Study-An Assessmentof Accident Risks in U.S. Commercial Nuclear Power
Plants," WASH-1400 (NUREG-75/014), October 1975.
S33
PUblic Citizen Inc., "Death and Taxes," mimeograph released April 5, 1979 at 1-3.

42 U.S.C. Sec. 103(d).
Summary of telephone conversation with SIG Consultant Allen Schultz.
S38
See text accompanying note 164, supra.
Johnson testimony before the Ohio PUC in 761174-El-AIR.
5401d. at XX-30.
541
See "Operating Units Status Report," NUREG-0020,
Vol. 3, no. 8, August 1979.
542 See note 127 supra and text accompanying.
5
The NRC Standards are not, however, regulations.
Rather they exist in Regulatory Guide 1.68 "Initial Test
Programs for Water-Cooled Nuclear Powerplants," andInspection and Enforcement Manual, Chap. 2415.
5"Notice this is a negative standard, so that "ties goto the utility". Unless the NRC witness could conclusively
state that the longer test period had no safety value,
FERC should not disallow any AFUDC associated with thelonger period.
545
See note 127, supra and text accompanying.
ST
To perhaps state the obvious: given a determined
rate of return on equity, the higher a utility's rate base,the larger the revenues allowed.
547 By contrast, public systems, such as the Tennessee Valley Authority (TVA), can afford to fund innovation.
For example, TVA recently announced that it would
require control room operators to have college degrees,
even though the NRC has no such requirements. TVA
can assume this added cost without fear of "goldplating"charges for two reasons. First, TVA is not regulated by
local PUCs and, hence, there are no fore for such arguments. And, second, even if these arguments were possible and succeeded, there are no "investors" (other than
taxpayers) who would be concerned- with absorbing theadded costs through methods other than rates.
54BIn re: Investigation of Outage of January-February
1976 at Vermont Yankee, Vermont Public Service Board,
Docket no. 4115 (October 13,1976).
See note 22 supra and text accompanying.
550
However, it should be recognized that the management decision "follows the engineering" conclusion thatthe plant is capable of operation. Schultz testimony
before the Ohio PUC in 76-1174-EL-AIR at XVII-157.
551
Schultz testimony before the Ohio PUC in 76-1174EL-AIR at XVII-157.
552
For example, as with TMI-2, it may relieve a construction manager of responsibility and put the utility infull control.
536
537

553 See text accompanying note 37 supra.

554

Actuaily, Toledo Edison sought rate recognition at apoint earlier than "commercial operation." The PUC
agreed and allowed rate inclusion when the unit had been
synchronized with the grid. In arguing against that before
the PUC, the Ohio Office of the Consumer Advocate
helped develop the record as to the significance of "commercial operation." Ultimately, the Ohio Supreme Court
overturned the PUC decision. Consumers' Counsel vs.
Pub. Util. Comm. (1979) 58 Ohio St. 2d., no. 78-1238,(slip opinion) (June 27, 1979). Although the Ohio Court
did not say "commercial operation" was the proper point
for finding a unit to be "used and useful," it did rule thatsynchronization was too early. Slip opinion at 5.

534
For example, if a licensee applied state-of-the-art
technology and installed approved equipment in a unit
which ultimately caused an accident, did the licensee
build and operate the unit "unsafely?"535"Artificial" deadlines, by our definition, are thoseestablished for nontechnical reasons, including suchmatters as tax years, test years and so forth.

25 8

57

MJohnson testimony before the Ohio PUC in 761174-E1-AIR.
556
10 C.F.R. Sec. 50.55a(g)(4ci), 10 C.F.R. Sec.
50.55a(g)(4)(iii), 10 C.F.R. Sec. 50.55a(g)(4)(b), 10 C.F.R.
Sec. 50.55a(g)(5)(iv),10 C.F.R., Part 50, Appendix J.
557
10 C.F.R. Sec. 50.55a(g).
Indeed, in light of the widespread use of the term"commercial operation" in the industry, perhaps the NRC
was simply trying to state a time in understandable terms.

eAnother possibility is to disengage the connection
between commercial operation and used and useful andallow PUCs to find a plant used and useful before commercial operation. This appears less likely after the Ohio
Supreme Court decision regarding Davis Besse, previously discussed.
- 577The problem with this tactic, of course, is thedanger of disallowance of AFUDC. See notes 103 and104 supra and text accompanying.
578
Tis was, in essence, the position of GPU withregard to TMI-2.
579
See also testimony of A. J. Schultz before the Ohio
PUC in 76-1174-EL-AIR at XVII-151.

NRC Regulatory Guide 1.16, "Instructions for Completing Operating Data Report," item 21, (August, 1975)
Regulatory Guides have no legal force. They are
one method (the staff's view) of complying with regulations.
"is information is included in the operating unit
reports, previously cited.
582
Each NRC official stated that the NRC had no
responsibility over a "declaration of commercial operation." Mosley dep. at 211; Davis dep. at 185; Kellogg dep.
at 54; Narrow dep. at 34; Hanauer dep. at 152; Haverkamp dep. at 98; Eisenhut dep. at 33.
MSchultz prepared testimony before the Ohio PUC in
76-1174-EL-AIR, at 10.

°IRS Letter Ruling 7833007, supra.
Rev. Rul. 79-98.
582 I nformally, some technical people at the IRS haveagreed to as much. See Dieckamp dep. at 110 (Pres.
Com.).
See text accompanying notes 542-548, supra.
5"Offices of consumer advocates, a recent development, are charged with representing the (generally, retail)consumer, with the goal of reducing the final bill.
5
WMeenan Oil Company, et al/ v. Philadelphia ElectricCompany, PaPUC R.I.D. 438 (December 28,1978).

Construction work in progress is a standard utility
account under the FERC system. (It is to be contrasted
with the plant in service account.), Balance Sheet Chart of
Accounts, 107. When CWIP is allowed in rate base, it
simply means that rate payers begin paying a rate of
return on the plant under construction and do not wait
until the PUC finds the plant "used and useful." 18 C.F.R.
Part 101. New Jersey allows CWIP in rate base.
Graham dep. at 17-18.
See also "Memorandum of Law: Criteria for Determining When a Nuclear Facility is Used and Useful," Filingof PaOCA dated October 31, 1978 in R-78060626 (R.I.D.
626) at 1, citing transcript of August 30, 1978 proceeding
at 4, 8. PaPUC AW equated "commercial service" and"used and useful."567
The term "used and useful" is from Smythe v.
Ames, 169 US 466 (1897). Graham prepared testimony
in FERC Docket no. ER 78-494.
sea" Memorandum of Law: Criteria for Determining
When a Nuclear Facility is Used and Useful," Filing of
PaOCA dated October 31, 1978 in R-78060626 (R.I.D.
626).
5%
Re Pennsylvania Water & Power Co., 82 PUR NS
193, 237 (1949 FPC), AS CITED IN PaOCA Memorandumof Law filed in PaPUC R-78060626.
570
Penn. Consol. Stat., Chap. 13, Sec. 1307(a) (1966).
571
See note 19 supra and text accompanying.
572Note that this timing question (when) is quite apartfrom the possibility of disallowance (how much) which has
been previously discussed. See note 126 supra and text
accompanying.
573
Herbein dep. at 117.
574
"Memorandum of Law: Criteria for Determining
When a Nuclear Facility is Used and Useful," Filing of
PaOCA dated October 31, 1978 in R-78060626 (R.LD.
626) at 3.
575
Schuylkill Valley Lines, Inc. v. PaPUC, 165 Pa.
Super. Ct. 393, 68 A.2d 448 (1949) as cited in I79040308, brief of PaPUC staff, at 11.

,5ss
FERC Docket no. ER 78-409 (Philadelphia ElectricCompany.) The effect of this split in interpretation of the
Salem plant is that investors look to see earnings fromthe common facility (per the FERC approach) but see
none (because of the PaPUC ruling).
587
For example, after the TMI accident, the PaPUC
removed TMI-2 from the Pennsylvania rate base, while itremained in the wholesale rate base of the GPU companies, pending final decision on the FERC rate increases
filed before the accident.

Except, of course, that different classes of customers pay on different methods of evaluating a plant's
worth.
8

Graham dep. at 44.
See text accompanying notes 578 and 579 supra.
The same proposition was, ironically, noted in the
PECO
Salem 1 decision (PaPUC R.I.D. 438).
592
R.LD. 438 at 37.

Although Congress did not establish the standards
which have defined "place in service," it has made it clearthat it does not want the benefits of ITC and accelerated
depreciation to "flow-through" to the ratepayer. 26
U.S.C. Sec. 46(f)5This is a matter of debate in public utility regulation.
M

NRC has continued to do so even after these allegations of "rush to commercial operation" were first madeSee "1978 Opening Saved Power Company Millions," The
Washington Star, April 5, 1979.
595

596

42 U.S.C. Sec. 2232(a).

598Operating costs include decommissioning costs.

597

10 C.F.R. 50.40b.

SECY-79-299, NRC staff paper, "Generic Issue of
Financial Qualifications: Licensing of Production and Utilization Facilities, April 27, 1979.
599

80

25 9

°Id. at 12.

See note 562 supra.

e02

Kelkgg dep. at

823

A li sting of startup tests in the FSAR is required by
10 C.F.R. Sec. 50.34(b)(6)(iii). The Staff has promulgated
NRC Regulatory Guide 1.68, "Initial Test Programs for
Water-Cooled Nuclear Powerplants," and NRC Regulatory
Guide 1.70, "Standard Format and Content of Safety
Analysis Reports for Nuclear Powerplants,"to assist licensees in drafting chapter 14 (initial test program) of theFSAR.
8247, question presented is whether a licensee candelete tests listed in the FSAR without NRC approval; andeven if such deletion is permissible under 10 C.F.R. 50.59,
whether the NRC is informed after the fact.
62sSee text accompanying note 535, supra.
626
The "good business" is both a matter of rewards
and punishment. A "reward" for safety might bei mproved operating efficiency. The "penalty," of course,i s that no utility wants the expense of a nuclear accident.
See NRC Staff Paper, SECY-79-299, April 27,1979, at 4.
would there not be a Coal Regulatory
827
Commission and a Hydroelectric Safety Commission?
628
See note 139 supra and text accompanying.
829
For a full discussion of "future test years" see note
85 supra and text accompanying.
830
See note 94 supra and text accompanying. Failingoutside the test year would have created a potential
argument as to the propriety of including TMI-2 in rate
base.
"For example, if TMI-2 had not gone into commercial
operation at all, although projected to do so in the June
1979 to June 1980 test year, the PaPUC could haveordered refunds to ratepayers for the amount collected.
Penn.
Consol. Stat. Chap. 13, Sec. 1312 (1966).
e32PUC of the State of California, Resolution no. M4706 at 3 (June 5, 1979).
The construction life of a nuclear unit spans anumber of years which may be prolonged by deferrals orunanticipated events.
834
See notes 102-129 supra and text accompanying.
See Northern States Power v. State of Minnesota,
405 U.S. 1035 (1972).
838
tt will be recalled that such a stipulation was agreed
to in the New Jersey Met Ed proceeding. See note 52
supra and text accompanying.
837
For example, the NRC might have provided useful
information as to the lengths of the shutdowns of fivereactors in early 1979 for seismic code concerns, so that
PUCs could assess the cost of replacement power.
6M
See note 587 supra and text accompanying.
6
MSee note 543 supra and text accompanying.
64
OCurrenty, use of this device is elective.
64'26 U.S.C. Sec. 46(c)(1)(A), 167.
642
1 RS Letter Ruling 7833007.
e43
See Library of Congress, Congressional ResearchService, "Nuclear Power: The Three Mile Island Accident
and Its Investigation," Issue Brief #IB79035 at Crs-6;
Nucleonics Week, August 16,1979 at 12.
"Even state PUCs have recently been subject tosuggestions" on how goal of enemy conform theirregulation to
Public Utilities Regulatory Policy Act of 1978, Pub. L. No.
95-617, 92 Stat. 3117. The national goal of nuclear
safety would seem deserving of similar attention.

55.

eo31n the Matter of Public Service Company of New

Hampshire, et al. (Seabrook Station Units 1 and 2, CLI78-1, 7 NRC at 1, 17 (1978).
old., 7 NRC at 20.
This apparently suggests that there is some "threshold" level of financial stability, above which an applicant
can be assumed to be "financially qualified." Thus, the"standard" by which to measure this threshold level was amajor issue in the Seabrook case. 7 NRC at 17. However, the standard used to measure financial qualification
is not as important as the length and depth of the financial review itself.
emln the Matter of Public Service Company of New
Hampshire, et al., (Seabrook Station, Units 1 and 2),
ALAB-422, 6 NRC 33, 108 (Dissenting Opinion of Mr.
Farrar)A07
As proposed in NRC Staff Paper, SECY-79-299,
April 27,1979. See note 599 supra and text accompanyings08
An article appearing in Nucleonics Week suggested
that the commission was favorably disposed toward
SECY-79-299 but was awaiting the report of this Special
Inquiry Group before taking final action. Nucleonics
Week, Vol. 20, no. 34 (August 23,1979).
Which appears to be the current practice. Seenote 598 supra and text accompanying. Recently, NRR
has also focused on the financial qualification of GPU to
operate TMI-1, See e.g., letters from F. D. Hafer, GPUSC.,
to Richard H. Vollmer, NRC. (October 17 and 19, 1979),
transmitting financial information.

Presumably this system would draw on information
obtained from the financial analysis office at NRR, previousy discussed.
"See "Revised inspection Program for Nuclear Power
Plants," NUREG 0397, NUREG 0425.
m2See e.g., Narrow dep. at 34.
813See note 43 supra and text accompanying. However, we propose such a requirement below.
6"The corporate pressures are (1) not to impose a risk
on shareholders by declaring commercial too early and(2) not to shift the risk of an incomplete plant to an
operating utility. See note 24 supra and text accompanyi ng.
810

The most recent IRS Letter Ruling (7833007) suggests completion of the tests is a prerequisite to a findingthat the plant is "place in service" in that tax year.
"For example, the PaPUC inquiries into the meaningof commercial operation produced from GPU a voluntary
linking of the test program and that declaration.
617
Haverkamp dep. at 89-90.

Such a careful power escalation would be required
if the last test performed involved a reactor trip. This was
the case at TMI-2 when the final test run in 1978 was thefull-power generator trip test.
"iThe NRC cannot and would not require commercial
operation.
e2°

For example, no worker should work excessive
overtime.

e2nSee text accompanying note 391, supra.
e22 Haver tramp dep. at 94-98.

260

APPENDIX 1.1

THE STATUTORY ORIGIN OF THE NRC's
ORGANIZATIONAL STRUCTURE

The U.S. Nuclear Regulatory Commission was
created by the Energy Reorganization Act of 1974,
Public Law 93-438.1 Its organizational structure
was the result of a compromise in conference ofdistinctly different approaches in the House and
Senate bills.
The House bill, H.R. 11510, 2 provided for a Nuclear
Energy Commission as a renamed Atomic Energy
Commission. 3 It redesignated the Director of Regul ation as the "Executive Director for Operations." 4Otherwise, the renamed Commission would havecontinued to perform the licensing and related regulatory functions which the AEC, its Chairman,
members, officers and components performed prior
to the effective date of the Act. 5 The House bill did
not change the existing organizational structure.
The report gives no indication that the duties of the
Executive Director for Operations would differ fromthe duties of the Director of Regulation.
The Senate bill, S. 2744, as introduced, 6 retained
the AEC regulatory organization in which a single
Director of Regulation supervised and reported to

the Commission on all licensing and other regulatory
activities. As reported, S. 2744 provided "for threecoequal Directors, each with direct and independent
access to the Commission, and each responsible forseparate operations relating to nuclear reactor
safety, nuclear 7materials security, and nuclear
safety research." As reported, S. 2744 establishedthe Nuclear Safety and Licensing Commission whichwas "based upon the Regulatory Division of the
AEC" but with "a revised internal organization topromote well-balanced and closely supervised regul ation of the burgeoning nuclear power industry." 8
The mission of the new Commission was "to ensure
the safety and the security of the nuclear industry
and the weapons-grade and other radioactive
materials used to fuel it."8 The committee's intention was to "upgrade the role of the Commission inits exercise of exclusively regulatory responsibilities
by insuring fullest possible access to all available
i nformation within the organization on the safety andsecurity of the nuclear power industry." 9
The report on S. 2744 offered the following com261

ment about the new regulatory organization which"has been designed by the committee to help [theNuclear Safety and Licensing Commission] effectively perform its function in all categories":10

generation of reactor, the Liquid Metal Fast Breeder(LMFBR)12

The committee stated its intent that the Directorof Nuclear Reactor Safety:

As reported by the committee, NSLC will have abipartisan, technically qualified Commission, which
will directly supervise a balanced three-part regulatory organization. The high-level position of Direcfor of Regulation is eliminated, thereby allowing theheads of the three key programs-safety, safeguards and research-direct access to the Commission and a freer interplay of regulatory proposals and priorities at the Commission level than is
now possible in the present system.
Each Director is appointed by and serves at thepleasure of the Commission.
It is the intent of the committee that an Office ofAdministration which now assists ... the Director ofRegulation, would be attached to the Chairman of
the Commission.
The committee intends that the Chairman of the
NSLC will see to the faithful execution of theCommission's policies and decisions and will coordinate and supervise the tripartite regulatory organi zation accordingly.
[T]he original bill ... would have simply renamed
the AEC the Nuclear Energy Commission, andretained the Regulatory Division intact, without
modification. This would have perpetuated thepresent system in which a Director of Regulation
supervises three directorates-for regulations,licensing and inspection-thereby exercising nearly
all the regulatory functions of the Commission. Thissystem has its purpose in the present AEC, wheretheCommissioners
exercisedevelopmental
responsibilities of a magnitude in terms of dollars,
manpower and physical resources that outweigh
the regulatory operations and facilities many times
over. Therefore, the Director of Regulation isneeded to supervise the day-to-day regulatory
responsibilities, while the Commission devotes thetime needed to develop new industrial technologythat is one of the modern wonders of engineering.

[W]ill continue to supervise the existing directorates
of regulations, licensing and enforcement as they
pertain to the safety of nuclear powerplants andother facilities in the licensed industry. As such, hewill remain the chief officer beneath the Commission responsible for safety. The other two Directors will be the chief officers on behalf of the Commission for safeguards and research respectively. 13

The committee established "a separate, coequalsafeguards Bureau to draw together and coordinate
all safeguards personnel who are now combinedwith ... [other personnel] and scattered among theexisting three regulatory directorates." 12
The revised organization, in the committee swords, was:[I]ntended to give balance to the new Commission
so that no one regulatory area is stressed to thedetriment of another. The Commission is in a position to weigh priorities and make decisions accordi ngly. In particular, safety and safeguards are given
equal recognition within the organization. This is anexpression of the Committee's judgment that they
are of equal importance in terms of public healthand safety and of the future of the nuclear powerindustry. 14

The committee noted that the continued
existence of the Atomic Safety and Licensing
Appeal Panel "will ensure that the Commission will
be able to oversee the licensing and rulemaking
workload while carrying out its principal administrative and coordinating functions essential to thenation's health, safety, security, and energy supply "15

Presumably, the overall management of the Commissi on would be the responsibility of the Chairman
who "shall see to the faithful execution of the policies and decisions of the Commission, and shallreport thereon to the Commission from time to timeor as the Commission may direct." 16 However, thecommittee did not explain what the dimensions of
the Chairman's authority were; how, other than withthe assistance of an "Office of Administration," 10 the
Chairman would be expected to carry out thisauthority; or how the Chairman's authority related tothat of the three coequal divisions, each under a
Director having direct access to the Commission.
The report does state that:

With only licensing and related regulatory responsibilities, the new Commissioners will now be in aposition to devote full time to the activities which
are presently supervised by the Director of Regulationr

There was no Executive Director for Operations
i n S. 2744 as reported. Instead, the committee
upgraded the Director of Regulation from a level V
to a level IV on the Executive Schedule andchanged his title to "Director of Nuclear Reactor
Safety." In this way, according to the report:[T]he former top regulatory position is assigned to
the Commission's largest and most challenging line
responsibility: licensing and otherwise ensuring thesafe operation of nuclear power reactors. Thisi ncludes two of the key areas in nuclear power: theperformance of the Emergency Core Cooling System (ECCS) in the current generation of Light Water
Reactors (LWR) and the development of the next

It is contemplated that the Office of Administration,
now attached to the Director of Regulation of the
AEC, will be attached to the Chairman of theCommission-to assist in coordinating the duties of
the three directors, consistent17 with the policies anddirectives of the Commission.

262

succeed, it will succeed only because it has outstanding men and women involved in it.
I really cannot imagine the Chairman assuming
those responsibilities if he or she did not reallyhave the authority to carry out the responsibilities
that have been thrust upon him or her by the intent,
purpose, letter, and spirit of the legislation before

H.R. 11510, as reported, was passed by theHouse on December 19, 1973, without pertinent
amendment. 18 The Senate passed S. 2744, as
amended, on Augkist 15, 1974, with an amendmentg:by Senator Perc Y that added the following:(2) The Chairman of the Commission shall be theprincipal executive officer of the Commission andhe shall exercise all of the executive and administrative functions of the Commission, including funstons of the Commission with respect to (A) the
supervisionofpersonnel
appointment
andemployed under the Commission (other than personnel employed regularly and fulltime in thei mmediate offices of Commissioners other than the
Chairman, and except as otherwise provided in thisAct, (B) the distribution of business among personnel appointed and supervised by the Chairman andamong administrative units of the Commission, and(C) the use and expenditure of funds.
(3) In carrying out any of his functions under theprovisions of this subsection the Chairman shall begoverned by general policies of the Commission
and by such regulatory decisions, findings, anddeterminations as theCommission may by law be
20
authorized to make.

US.

The explanation also included these remarks by
Senator Ribicoff, the bill's manager on the floor:

The committee, in its report, states that the Chairman is provided this supervisory authority in section 201, which cites him as the one who 'in behalfof the Commission, shall see to the faithful execution of the policies and decisions of the Commission.' This same language is used in the Atomic
Energy Act to describe the authority of the Chairman of the AEC, and it was incorporated into thisbill to apply to the authority of the Chairman of theNSLC.
At the same time, the committee has designed a
new regulatory organization for the NSLC, which
will require a more active role by the Commission
than is presently the case in the AEC. The bill
establishes three basic, coequal divisions-safety,
safeguards and research--each under a Director
having direct access to the Commission. The posilion of Director of Regulation, which now oversees
regulatory operations while the Atomic Energy
Commission directs most of its energies todevelopmental matters, is abolished under the bill.
With nuclear developmental and promotional
responsibilities transferred to ERDA, the new NSLC
will devote full time to regulatory activities which
are presently supervised by the AEC's Director ofRegulation.
The new regulatory organization is designed topermit a freer interplay of regulatory proposals andpriorities at the Commission level than is now possible in the present system. Hopefully, crucial
safety and safeguards issues, which are now
sometimes buried or modified at lower bureaucraticlevels, will be aired and resolved by the Commission itself.
Obviously, the Commission will be playing amore active supervisory role in regulatory affairs
than is now the case, and the committee intends
that the Chairman will be instrumental in coordinating the activities of the three regulatory divisions
accordingly.
The committee report states, for example, thatan Office of Administration which now assists the
Director of Regulation, would be attached to the
Chairman of the Commission.
The Percy amendment goes beyond the generallanguage of the Atomic Energy Act to specify that
the Chairman of NSLC 'shall be the principal executive officer of the Commission, and he shall exercise all of the executive and administrative functions of the Commission.' This would include thesupervision of, and distribution of business among,the three Directors and other executive-level personnel appointed by the Commission.
This language, which is identical to that contained in nine other regulatory commission statutes,

The purpose of this amendment, in the words of
its sponsor, was "to insure that the NSLC chairman
has adequate power to perform his functions."20
The explanation of the amendment included the foll owing remarks by Senator Percy:
I recognize that the committee report addresses
the problem. It states that it is the committee's
understanding that the Chairman of the Commission
will
responsiblefori mplementing
thebeCommission's policies. And the report states thatan Office of Administration is to be attached to the
Chairman of the Commission. But the language ofthe bill should be amended to provide explicitly forthe clear assignment of primary administrative
responsibility to the NSLC Chairman. Not to do sowould be to risk the development of a chaoticorganization subject to crippling conflict among
three strong, coequal Bureau of Office Directors.
If the Chairman of the Commission were weakened by the absence of strong administrative
authority, if the other members of the Commission
strongly contested the implied-but not explicitpower of the Chairman, the functioning of the Commission could be tragically impaired. I submit thatthe assignments of the Commission are of suchgravity and such overwhelming significance to thesafety of our population that we cannot afford evento risk the possibility that the Commission will beadministratively impaired in carrying out its mission.
Mr. President, this amendment has the strong
support of the Office of Management and Budget
and the Atomic Energy Commission. Because it
assigns to the NSLC powers now held by nineother Federal Commissions, there should be nocontroversy about its acceptability.
Mr. President, my last point is probably the mostimportant because if this activity is to really263

will insure effective supervision of the NSLC organization by the Chairman on behalf of the Commission. The Percy amendment is consistent with the
purpose and the more general language of thebill.22

H.R. 11510 then went to conference to resolve
the differences between the House and Senate.23
The conference substitute deleted the provision
for placement of executive and administrative functions in the Chairman. 24 The reason for this was
the conferees' belief "that the duties and responsibilities of the Chairman and the members, and theadministrative arrangements as provided in this Act,are fully adequate to effectuate its purpose."24
The conferees' substitute followed the Senate
language with modifications in providing three "coequal administrative or operating units titled, respectively, the Office of Nuclear Reactor Regulation, theOffice of Nuclear Material Safety and Safeguards, and the Office of Nuclear Regulatory
Research .... "25 According to the conferees, thisarrangement "will provide ample flexibility in theCommission to devise the most effective administrative arrangements within its own organization and at
the same time give due and proper emphasis tofunctions which are vital to the public health andsafety and the safe and efficient operation of
nuclear powerplants and other licensed facilities." 26
The conferees substituted a section 209 which"follows the House language in providing for an Executive Director for Operations." 26 As the conference report explained:

now defunct Energy Research and Development
Administration). 27 The following excerpt appears to
explain the conferees' intent in section 209:
Senator Percy: We might as well eliminate the
Executive Director if they report directly everything.
The purpose of that Executive Director is to screenout most of those things. Now, you are not goingto have a good Executive Director if he sits in there,
he's got a title, and he's got no authority whatsoever.
But, you are going to have better Commissioners if they know they've got the power to go
directly, and you are going to find the Executive
Director more responsive if he knows they can do it
directly if they can't do it through him.
Representative Holifield: I think the Senator's logic
i s irrefutable, and that is my concept of this. I wantthat kind of concept.
Representative Fuqua: Mr. Chairman, I don't think
what Senator Percy has in mind, I don't think that
language does that.
Senator Percy: That's why it's important to leave
when they deem it necessary; that's the reason for
it?s

The Aftermath

On June 17, 1975, Senator Baker offered anamendment to the Nuclear Regulatory Commission's
authorization bill for fiscal year 1976, S. 1716, to ensure that the Chairman of the NRC has adequate
power to perform his functions. 29 The amendment
was adopted and was subsequently enacted in Public Law 94-79. 30 In essence, this amendment restored to section 201 of the Energy Reorganization
Act, the "principal executive officer of the Commission," language which31,32
had the previous year been
deleted in conferenceSenator Baker made the following remarks when
he offered the amendment

The Act does not specify his [the Executive Direcfor for Operations] functions, leaving that determination to the Commission's discretion and judgment. However, it is expected that the Executive
Director for Operations will be the coordinating anddirective agent below the Commission for the effective performance of the Commission's day-to-day
operational and administrative activities. He will
coordinate and direct in behalf of the Commission,
the operating and administrative units.
At the same time, the conference substitute provides that the head of each component provided in
the conference substitute shall be able to communicate with and report directly to the Commission
itself whenever he deems necessary to carry out
his responsibilities. In this way, the conferees makeit clear that the Executive Director for Operations
will not be able to suppress or limit informationneeded for the Commission's discharge of its own
collective responsibilities. 26[T]he purpose of the amendment is to assure that
the Chairman of the Nuclear Regulatory Commission has adequate power to perform his functions.
The statutory language in section 201 of the Energy
Reorganization Act of 1974 pertaining to the chairmanship of the NRC is quite restrictive, at least
when it is compared with the statutory language regarding the role of the Chairman of other independent agencies such as the CAB, FPC, ICC, FTC andSEC.
,"

I n spite of a statutory mandated organizational
structure which calls for leadership of the highest
caliber to manage successfully, there is no statutory provision, either for the designation of a chief
executive officer, or for the grant of authority tothat officer. The obvious leader of the Nuclear Regulatory Commission, or any other independent regulatory agency, is its Chairman. A Chairman must

The subject dealt with in section 209 was discussed in the Joint Conference Committee's sessionof October 3, 1974. The transcript of this session isreproduced in the "Legislative History of the Energy
Reorganization Act of 1974", Vol. 2 (compiled by the264have the necessary statutory authority to carry out
the executive and administrative functions needed
to manage and lead the Commission.

cate directly with the Commission when they consider it necessary in carrying out their responsibilities.38

On November 5, 1979, the person who has been
Executive Director for Operations since the NRC
was created on January 19, 1979, in stating his intendon to resign from that position, observed:

This amendment is needed to provide explicitly forthe clear assignment to the Chairman of the primary administrative responsibility for the implementation of NRC's policies. Not to do so would be torisk the development and growth of an organizational structure with weakened leadership. This
would lead to crippling conflict among responsible
officials which clearly would not serve the public interest. If the Chairmanship of the Commission were
weakened by the lack of clear and explicit administrative authority, the functioning of the Commission
could be significantly impaired.... 33

I recognize that there are many pressing demands
that the Commission must meet in the coming
months, and that some time will be required for theCommission to clearly define the relationships
between the Commission, the Executive Director
for Operations, and the major program OfficeDirectors-a step which I believe to be absolutely
necessary before selecting my successor.

In 1978, section 209 of the Energy Reorganization Act of 1974, as amended, was amended by adding the following sentence at the end of subsection(b):July 19,1977
MEMORANDUM James L. Kelley
FOR:
Acting General Counsel

Notwithstanding the preceding sentence, each suchdirector shall keep the Executive Director fully andcurrently informed concerning the content of all
such34direct communications with the Commission.

This amendment was included in the report on S.
2584, the NRC's authorization bill for fiscal year
1979, by the Committee on Environment and Public
Works, United States Senate. This report stated
that, in addition to the Directors of three statutory
offices who may report directly to the Commission,
the NRC practice also allows the Directors of theother staff offices to report directly to the Commission "if the Director deems it necessary to carry out
his responsibilities."~ The committee stated in its
report that "it supports this policy, especially in thecase of the statutory offices and the other two major line offices [Standards Development, and Inspection and Enforcement].^3s
Continuing on this subject, the committee statedi n its report:

FROM:

Stephen S. Ostrach
Attorney, OGC

SUBJECT:

POWERS OF THE CHAIRMAN
OF THE COMMISSIONSUMMARY:
The powers of the Chairman are virtually identicalto those of the Chairman of other major regulatory
agencies such as the FTC, FPC, CAB and SEC.
The legislative history concerning the relationshipbetween the Chairman and the Commission is notentirely clear but it shows that the Commission is
primarily intended to function as a collegial body ofwhich the Chairman is the head
head.
DISCUSSION:
As originally enacted by Congress in 1974, section 201 of the Energy Reorganization Act was carrigid over without change from section 21 of the'Atomic Energy Act of 1954. Section 21 had beenquite carefully drawn to restrict the exercise of
power by the Chairman of the AEC over the otherCommissioners. During the hearings prior to enactment of the Atomic Energy Act in 1954 several of
the sitting Commissioners testified before the Joint
Committee on Atomic Energy that the then Chairman of the AEC, Admiral Lewis Strauss, was limiting
their access to information and to the President andthat the functioning of the Commission as a collegial
body was being impaired.
In response to these complaints section 21 of theAtomic Energy Act specifically provided (and sec-

There appear to be problems with the ability of the
Office of Executive Director for Operations to propery discharge its responsibilities. The committee isconcerned that this situation may be caused by theprovision in existing law which permits Office Directons to communicate directly with the Commission
and leave the Executive Director uninformed of important matters.
The present Executive Director has reported
that during the period from formation of NRC in1975 until approximately April 1977 there was astrong tendency for the Office Directors and theCommissioners to deal directly with one another,even on routine matters. On May 13, 1977, theCommission issued a new manual for the Executive
Director for Operations (EDO) which, in effect, provides that the Office Directors shall report to the
EDO although they still have the right to communi265

tion 201(a)(1) of the Energy Reorganization Act still
provides) that:

Each member of the Commission, including the
Chairman, shall have equal responsibility andauthority in all decisions and actions of the Commission, shall have full access to all information
relating to the performance of his duties or responsibilities, and shall have one vote.

This explicit commitment to the concept of theCommission as a collegial body acting only throughthe joint vote of a quorum was a direct legislative
response to a perceived problem, has not beenaltered in the intervening years and is the essential
backdrop against which the powers of the Chairman
must be viewed.
The Chairman's role as "the official spokesman of
the Commission" in its relations with Congress andothers and his responsibility to "see to the faithfulexecution of the policies and decisions of the Commission" were given to his office by section 21 of theAtomic Energy Act and have been carried overi ntact in the text of section 201(a)(1) of the Energy
Reorganization Act. All of the other powers of the
Chairman are found in subsections (a)(2)-(a)(5) ofsection 201. These subsections were added to the
ERA by ammendment in 1975. Pub. L. 94-79, Sec.
201. Those subsections provide:(2) The Chairman of the Commission shall be theprincipal executive officer of the Commission, andhe shall exercise all of the executive and administrative functions of the Commission, including functions of the Commission with respect to (a) theappointment
andsupervisionofpersonnel
employed under the Commission (other than personnel employed regularly and full time in theimmediate offices of Commissioners other than the
Chairman, and except as otherwise provided in the
Energy Reorganization Act of 1974). (b) the distribution of business among such personnel andamong administrative units of the Commission, and(c) the use and expenditure of funds.

(3) In carrying out any of his functions under theprovisions of this section the Chairman shall begoverned by general policies of the Commission
and by such regulatory decisions, findings, anddeterminations as the Commission may by law be
authorized to make.

ducing the amendments offer the only significant
legislative history. In part, Senator Baker said:[T]he purpose of the amendment is to assure that
the Chairman of the Nuclear Regulatory Commission has adequate power to perform his functions.
The [pre-existing] statutory language in section
201... is quite restrictive, at least when it is compared with the statutory language regarding the roleof the chairman of other independent regulatory
agencies such as the CAB, FPC, ICC, FTC andSEC.... mhe statutory position of the Chairman of
the Nuclear Regulatory Commission is relatively
weak in comparison with the arrangements in mostother agencies.
A Chairman must have the necessary statutory
authority to carry out the executive and administrative functions needed to manage and lead the Commission.
This amendment is needed to provide explicitly forthe clear assignment to the Chairman of the primary administrative responsibility for the implementation of the NRC's policies. Not to do so would be
to risk the development and growth of an organizational structure with weakened leadership. This
would lead to a crippling conflict among responsible
officials which clearly would not serve the public
i nterest.

Put quite simply the Chairman of the Commission must have the responsibility to carry out the
responsibility that has been placed on the Nuclear
Regulatory Commission under the Atomic Energy
Act of 1954, the Energy Reorganization Act of 1974
and the National Environmental Policy Act. I repeat
again that this amendment would give the Chairmanof the Nuclear Regulatory Commission the authority
which is now held by the long-established Federal
regulatory agencies.
I believe it [the amendment] brings the NRC into
conformity with other practices....
Remarks of Senator Baker, S10829-30, Cong. Rec.
Daily Ed. (June 17, 1975).

The language of the Baker amendment is virtually
identical to Reorganization Plans Numbers 8, 9, 10,
and 13 of 1950, U.S.C. App., which transfer certain
functions of the FTC, FPC, SEC and CAB to their
Chairmen, with the single exception of the phrase"principal executive officer" which is not found in
those plans. It is also quite similar to Reorganization
Plan Number 1 of 1969, 5 U.S.C. App., which(4) The appointment by the Chairman of the headsof major administrative units under the Commission
shall be subject to the approval of the Commission.
(5) There are hereby reserved to the Commission

its functions with respect to revising budget estimates and with respect to determining upon the
distribution of appropriated funds according tomajor programs and purposes.

The subsections were added to the original ERA
by a floor amendment to the NRC authorization billfor fiscal 1976. Senator Baker's comments in intro-

transferred certain functions of the ICC to its Chairman. As Senator Baker said, the major purpose of
his amendment was to make the Commission's for26 6

mal administrative structure the same as that ofother regulatory agencies.
The key provision of the Baker amendment is theone that makes the Chairman the "principal executive officer of the Commission" and directs him to"exercise all of the executive and administrative
functions of the Commission." But this provisionmust be read along with subsection 201(a)(3) which
provides that in carrying out his functions under
section 201, the Chairman "shall be governed bygeneral policies of the Commission and by such
regulatory decisions, findings, and determinations as
the Commission may by law be authorized to make."
These provisions could be reconciled by creating asomewhat unrealistic dichotomy between "executive
and administrative" functions which would be theresponsibility of the Chairman and "policy" questions that would be for the entire Commission.
Resolution of how to decide matters failing in thegray area between the polar extremes of purely
administrative and pure policy issues has to beresolved by the Commission and the Chairman on acase-by-case basis.
Analyzing the specific language of the Baker
amendment shows that it does give the Chairman
considerable authority. In addition to being the principal executive officer of the Commission, he isgiven apparently sole authority to exercise all of theCommission's executive and administrative functions. Specifically, subject to the exceptions noted
below, he can appoint and supervise all personnel
under the Commission; he can distribute businessamong the personnel and offices of the Commission;and he can determine the use and expenditure of
appropriated funds.
However, the Baker amendments do contain anumber of explicit limitations on the Chairman's executive powers in addition to the implicit limitation
created by the Commission's power to create policy
pursuant to subsection (a)(3). First, the Chairman

does not have the authority to supervise personnel
working
directly for anotherCommissioner.
Second, the authority to revise budget estimates
and to determine the distribution of appropriatedfunds among major programs and purposes isreserved to the Commission.
More importantly, the Chairman's power to makeappointments of the "heads of the major administrative units under the Commission" is subject to theapproval of the Commission. The quoted phrase is
not defined either in the Baker amendment or in its
scanty legislative history and is taken directly fromthe reorganization plans referred to above. It is
generally agreed that the phrase includes more than
the four "statutory" Commission offices which were
explicitly referred to in the ERA (Executive Directors
for Operations, Office of Nuclear Regulatory
Research, Office of Nuclear Material Safety and
Safeguards, Office of the Nuclear Reactor Regulation). Precisely how much more it includes is aquestion that has never arisen in view of the pastpolicy of Chairman Anders and Rowden to consult
with their fellow Commissioners on all arguably significant appointments as well as on all policy questions. It should also be noted that in the past it has
been the practice of Commission officers to informthe Commission prior to making any appointment to
a supergrade position and to obtain their approval
prior to making any appointment to a position at the
Office Director or any higher level.
To summarize, the Chairman clearly has considerable authority over the staff and responsibility forsupervising it in the conduct of its duties. The
extent to which this authority may or must be
shared between the Chairman and the Commission
is not clearly defined. Past practice by both Chairmen of the NRC has definitely been in the directionof offering maximum opportunity for the Commission
to participate in deciding all significant matters.

267

-9REFERENCES AND NOTES'Energy Reorganization Act of 1974, Pub. L. 93-438,
88 Stat. 1233 (1974).
2
H.R.11510, 93rd Cong., 2d Sess.
3
93-707,93rd
Cong.,
1st
H.R.
Rep.
No.
Sess.(December 7,1973).
4
1d. at 38, 45, 58.
5/d. at 34.
6
S. 2744, 93rd Cong., 2d Sess.
7
S. Rep. No. 93-980, 93rd Gong., 2d Sess. at 9.
1d. at 2.
1d. at 75.
tOld. at 22.
11
1d. at 22-23.
12
ld. at 23.
13
14. at 73.
14
14. at 25.
'5Id. at 58.
18
1d. at 22,104.
171d. at 55.
18
119 Cong. Rec. H11755 (daily ed.).
19
120 Cong. Rec. S15048, S15114 (daily ed.).
20
11. at S15048.
21
1d. at S15048-S15049.
8

9

22

14. at S15049.
120 Cong. Rec. S15114 (daily ed., August 15, 1974),
and H9444 (daily ed., September 23, 1974).
24
H.R. Rep. No. 93-1445, 93rd Cong., 2d Sess. 32(October 8,1974).
25
14. at 35-36.
28
14. at 36.
27
Energy Research and Development Administration,"Legislative History of the Energy Reorganization Act of1974," Vol. 2, p. 1707 et seq., transcript pp. 63-65, 76,
and 79-85.
28
14. at transcript pp. 84-85.
29
121 Cong. Rec. S10829 (daily ed.).
30
Pub. L. No. 94-79, 89 Stat. 413 (1975).
31
See 121 Cong. Rec. S10829 (daily ed.).
32
See H.R. Rep. No. 93-1445, 93rd Cong., 2d Sess.
32 (October 8, 1974).
33
121 Cong Rec. S10829-S10830 (daily ed.).
34Pub. L. No. 95-601, 92 Stat. 2949 (November 6,1978).
35
S. Rep. No. 95-848, 95th Cong., 2d Sess. (May 15,1978).
38
14. at 21.
23

26 8

APPENDIX 1.2

AGREED-UPON DIVISION OFRESPONSIBILITY BETWEEN NRR AND IE
WHERE THEIR FUNCTIONS INTERFACEI E needs current information on licensee commitments; therefore NRR will inform IE promptly of any
approvals, agreements or proposed actions withlicensees by copies of minutes of meetings or othercorrespondence regarding design, installation, or
procedure which differ from SAR or other commitments.

1. DESIGN REVIEW/INSPECTION INTERFACE
NRR is responsible for evaluating facility design
and programmatic plans (QA program, security plan,
emergency plan, preoperational and startup test
programs), as described in the SAR and other documents for conformance with NRC requirements. IE
is responsible for inspecting licensee facilities toverify implementation of the design and programmatic plans described in the SAR and other documents. IE will inform NRR of the results of such inspections. To enhance their understanding of thedesign commitments described in the SAR, NRR
personnel may need to visit facilities sites. NRR will
inform and/or invite IE to all site visits, thereby facilitating subsequent followup inspection activities by
IE. IE will inform NRR on a timely basis of any SAR
commitments IE believes are not inspectable orconsistent with NRC criteria. NRR will inform IE of
special emphasis that should be placed on verifying
licensee implementation of SAR commitments.

2. COORDINATION FOR LICENSING ACTION
NRR has responsibility for all NRC licensing actions related to reactor facilities licensed under 10
CFR Part 50. IE has the responsibility for making
certain findings with respect to licensee/applicant
activities as pre-requisites for some licensing actions and therefore appropriate "hold points" in theli censing procedures are established so that licensing action will not proceed until appropriate findings
have been made by IE. IE will keep NRR informed ofprogress made toward reaching the required find-269

STS or non-standardized TS, requiring revision
which are identified as not inspectable, enforceable,or that need NRR attention as the result of IE reviews or IE inspections. NRR agrees to inform IE
regarding the disposition of all such items identified.

i ngs and will conduct inspections as necessary tominimize any delays in licensing action.
3. COORDINATION FOR ENFORCEMENTACTION

6. 10 CFR 50.59 DETERMINATIONSI E is responsible for effecting enforcement action
upon detection of instances where the rules and regulations of the NRC have been violated. Significant
enforcement action has a bearing on pending
licensing action; therefore, IE will notify NRR of all
proposed enforcement actions that involve movetary penalties or more severe sanctions.

I E is responsible for reviewing changes to the facility and to procedures that were made and documented in accordance with 10 CFR 50.59 requiremarts. IE is also responsible for forwarding to NRR,i nformation detected during inspections relating tochanges made to the facility or the procedures
which may involve an unreviewed safety question as
defined by 10 CFR 50.59. NRR will provide timely
feedback to IE indicating whether or not the issues
identified . by IE constitute an unreviewed safety
question and for this reasons, or otherwise, require
NRR review.
NRR is responsible for review and approval oflicensee-requested license amendments or technical specification changes relating to changes to thefacility which require prior review and approval by
NRC. The NRR approved changes will serve as thebasis for any IE inspection of the change or modification.
IE is responsible for inspecting the approved
change/modification to verify that it has been performed and tested in accordance with commitments,
the requirements of the amendments and related
safety evaluations. IE will verify that appropriate
operating procedures have been prepared and thatthe new or modified system has been completed
and is ready for initial operation.

4. QUALITY ASSURANCENRR has the responsibility for review and acceptance of quality assurance program descriptions
presented in SARs or topical reports. IE has the
responsibility for reviewing the associated implementing procedures to assure their acceptability
with regard to carrying out the program description
commitments and meeting NRC requirements.
I n order to assure proper coordination on QA
matters, IE and NRR agree to: (a) participate jointly
i n predocket conferences with new utility applicants;(b) coordinate prior to completing action on docketi ng of SARs, acceptance of QA topicals andpreparations of SERs; (c) provide joint testimony tohearing boards when issues involving the adequacyof quality assurance programs are raised; (d) inform
each other regarding matters having significant
quality assurance implications; and (e) request comment on interfacing programs and activities.

7. 10 CFR 50.54(p) DETERMINATION

5. TECHNICAL SPECIFICATIONS AND
LICENSE CONDITIONSIE is responsible for reviewing changes to the facilities' security plan that were made by the licensee
and considered not to decrease the effectiveness ofthe security plan and documented in accordancewith 10 CFR 50.54(p) requirements. If IE disagrees
with or questions the validity of the licensee's conclusions that effectiveness is not decreased, IE willrefer the matter to NRR for resolution. IE is also
responsible for forwarding to NRR information
detected during inspections relating to changes
made to the facilities' physical protection systems,
security plans or procedures which may decrease
the effectiveness of the security plan. NRR will provide timely feedback to IE indicating whether or not
the issues identified by IE constitute a decrease ineffectiveness of the security plan.

NRR is responsible for developing and issuingcenses,including radiological-safety and environli
mental technical specifications (TS), for operating
facilities and for review and approval of licensee
amendments including TS changes. IE is responsible for enforcing compliance with the TS. All
operating licenses are now being issued with standardized radiological-safety technical specifications(STS), which IE has reviewed and found to be inspectable and enforceable. NRR will provide IE the
opportunity to review proposed TS which differ significantly from the STS to ascertain whether the
specific TS requirements are inspectable and enforceable. IE will inform NRR of any TS items, in270

NRR will inform IE of the resolution of suchmatters and will provide periodic status information.
for items requiring an extended period of time forresolution.

8. RESPONSE TO LICENSEE EVENT REPORTS
I E is responsible for the initial review of andresponse to notification of reportable events received from reactor licensees. IE will review each
event and make a determination as to the acceptability of the licensee's corrective action or programfor correction. IE will assure that information regarding significant events is provided to NRR in ati mely manner commensurate with the importance ofthe event. If the corrective action cannot be accomplished under the existing license requirements, if an
unreviewed safety or safeguards question is identified, or if technical issues requiring special expertisenot available within IE are involved, responsibility for
resolving the matter will be formally transferred to
NRR. NRR will inform IE of the resolution of any
such matters.

11. NRC RESPONSE TO INCIDENTS
NRR and IE response to incidents will be in accordance with the guidance contained in NRC
Manual Chapter 0500.
IE is responsible for managing the initial NRC
response to incidents until the Executive Management Team is available. During this interim period,
NRR will provide prompt technical assistance to IE
when requested. As soon as the Executive
Management Team is assembled, it will assume fullmanagement of NRC incident response activities.
The EDO will be kept fully informed. IE will notify
NRR promptly of known significant facts pertaining
to incidents. Likewise, NRR will notify IE promptly
when NRR is initially made aware of significant facts
i nvolving an incident.

9. RESPONSE TO OTHER MATTERSREPORTABLE TO IE
I E is responsible for the initial review of andresponse to matters reportable to IE under NRC requirements such as 10 CFR 50.55e and 10 CFR Part
21. IE will review each such report, investigate as
appropriate, and make a determination as to the acceptability of the reported corrective action or program for correction. If the corrective action cannot
be accomplished under existing NRC requirements,
if unreviewed safety questions are raised, or if
technical issues requiring special expertise notavailable within IE are involved, responsibility for
resolving the matter will be formally transferred to
NRR. NRR will inform IE of the resolution of suchmatters.

12. IE BULLETINS AND CIRCULARSIE has the responsibility for issuing Bulletins andCirculars. Bulletins are issued when a significant
safety or safeguards issue is involved, when prompt
i nvolvement of licensees is desired, when specificactions are recommended to the licensee and whena response is requested from the licensee. Circulars are issued to distribute information of generici nterest to licensees, but do not require written
response from the licensee. IE will consider Bulletins or Circulars which may be proposed by any
NRC office, but retains ultimate responsibility for thedecision regarding issuance.
I E will give NRR an opportunity to comment on all
proposed Bulletins or Circulars prior to their issuance, however, IE has the prerogative to accept
or reject any comments. IE will respond to NRR
comments not incorporated in substance into a Bul-'letin or Circular. If NRR specifically requests that a
Bulletin or Circular not be issued as proposed, thematter will be resolved at the Division Director level.
When a proposed Bulletin requests action which
could alter existing license requirements, IE will obtain NRR concurrence before issuance of the Bulletin.
IE has responsiblity to evaluate licensee
responses to Bulletins except when that response
alters an existing license condition. IE will provide asummary of the responses to NRR and if NRR ac-

10. HANDLING OF SAFETY AND SAFEGUARDS
PROBLEMS

Significant safety and safeguards related problems beyond those reported formally by licensees
may be identified by IE or NRR as a result of site
visits, inspections, allegations, informal communications with the licensee, or other sources. The resol ution of such matters should normally be achieved
through the IE enforcement procedures where possible. When resolution cannot be accomplished inthis manner, and neither IE nor NRR have clear
responsibility for resolving the matter, responsibility
will be formally transferred to NRR. IE will provide
NRR with all available information and may makerecommendations to NRR regarding disposition of
the matter.
271

tion is required, all responses, together with theli cense. IE is also responsible for verifying thatsummary and possible recommendations for resolu-

training and requalification programs have beention, will be forwarded to NRR.

conducted in accordance with commitments madein the SAR, in the license applications, and those re-quirements established in 10 CFR 55. IE will provide

13. NRR GENERIC LETTERS

NRR any information obtained during inspections

which may impact on the issuance or renewal of an

NRR has the responsibility for requesting infor-

operator's license and will effect enforcement ac-

mation needed for review of generic issues. If thelion, as appropriate.

i ssue can be expected to impact on the IE inspec-tion program, NRR will give IE an opportunity tocomment prior to issuance of such letters and will

15. MEETINGS WITH LICENSEES

i nform IE of all letters issued. If IE specifically re-quests that a Generic Letter not be issued as pro-

IE will be notified in advance of all NRR meetings

posed, the matter will be resolved at the Divisionpertaining to licensing actions which could impact

resulting from the review of generic issues.

advance of all IE meetings which could have impact

Director level.

NRR will inform IE of any actions

on the inspection program. NRR will be notified inon licensing activities.

Such notifications will bemade to a single designated point of contact.

14. OPERATOR LICENSING

For NRR/IE interface matters, the principal pointsof contact within NRR are the Director, Division of

NRR is responsible for evaluating training pro-

Project Management, or his designee, for all mattersgrams and requalification programs, as described inrelated to reactor construction projects, and thethe SAR and other documents, for conformance

Director,with NRC criteria. Further, NRR is responsible for

DivisionofOperating Reactors, or his

designee, for all matters related to operating reac-evaluating applications from individuals for operator

tors.

and senior operator licenses, including those forWithin IE, the principal points of contact are

the Director, Division of Reactor Inspection Pro-

renewal or amendment of existing licenses. Also,

grams, or his designee, for all safety and environ-

NRR reviews facility examinations administered as

mental matters related to reactors, and the Assis-

part of the licensed operator requalification pro-tant Director for Safeguards for all matters related

grams to determine whether the scope and depth

to safeguards.

are comparable to the NRC-administered examina-

The matters described above will be reviewed attions. NRR will notify IE of any approved changes inregular intervals to assure they represent currenta facility licensee's training program.

positions, and NRR/IE Interface Meetings will be

performing consistent with the provisions of theirmatters involving the two Offices.

I E is responsible for verifying that operators areheld at approximately monthly intervals to discuss

272

APPENDIX 1.3

PLANT DESIGNS LICENSED TO
OPERATE USING B&W
NUCLEAR STEAM SYSTEMSUnit
I ndianPoint 1

Oconee 1
Oconee 2
Oconee 3

TMI-1
CrystalRiver 3
RanchoSeco 1
Arkansas 1
TMI-2
Davis Besse 1

ReactorMegawatts
ThermalPlant
Megawatts
Electric

585

265

Construction
PermitDocket Date

Construction
PermitDate

Operating
LicenseDate

4/2/55

5/4/56

3/26/62

5/3/67

5/18/68

6/24/74

11/20/67
11/29/67
4/29/68
8/1/691 0/11/68
1 2/6/68
11/4/69
3/24/71

2568
2568
2568

887
887
887

1 2/1/66
1 2/1/66
1 2/1/66

2452

825

8/10/67

2535
2772
2568
2772
2772

819
913
850
906
906

273

11/6/67
11/6/67
11/6/67

9/25/68

2/6/73
1 0/6/73
7/19/74
1 2/3/76

8/16/74
5/21/74
2/8/78
4/22/77

APPENDIX 1.4

LICENSING ORGANIZATION, 1969 TO 1979
The Directorate of Licensing, the largest of thethree directorates, would perform all staff review
and processing of applications for and amendments
to licenses, and would conduct the program forlicensing of reactor operators. This directorate wasalso responsible for the review of applicant's submittals in compliance with the National Environmental Policy Act of 1969, and would prepare environmental statements for each plant application. The
Directorate of Licensing was comprised of threesubordinate directorates each headed by a deputy
to the director of licensing. Edson Case was theacting Director of Licensing for most of 1972, until
John O'Leary was appointed to the post.
The deputy director for reactor projects headed
four assistant directorates that were collectively
responsible for the project management of applications to construct and operate new plants and forthe project management of licensing matters involving operating plants. For applications in process,reactor projects managed both safety reviews andenvironmental impact reviews.
The deputy director for technical review managed
three assistant directorates comprised of technicalspecialists that performed the specific and detailed
reviews of material submitted by applicants forli censes. These groups also reviewed technical material received from operating plants in conjunction
with applications for amendments to their licenses.
The technical review was generally done in
response to specific project directives received
from the reactor projects directorate.

Staff Organization, Postconstruction Permit Review
Period, 1969-1974
In March 1970, the part of the regulatory staff
that was engaged in the review of new reactor plant
applications was reorganized. Within the Division of
Reactor Licensing directed by Peter Morris, the assistant directorate for reactor technology was abolished and most of the personnel were assigned to
the Division of Reactor Standards, where two additional technical specialist branches were created.
Also within the Division of Reactor Licensing, theproject management function was expanded as theformer assistant directorate for reactor projects became two assistant directorates, one for boiling water reactors and one for pressurized water reactors.
The reorganized divisions are shown in App. FigureI-1. This organization remained, with minor changes
due to expansion, through 1971.
I n July 1971, James Schlesinger was appointed
Chairman of the AEC and L. Manning Muntzing became the new Director of Regulation, replacing
Harold Price. In April 1972 the regulatory staff
under Muntzing was completely reorganized, as
shown in App. Figure 1-2.1 Seven divisions became
three directorates. The former Division of Reactor
Standards gave up its direct role in reviewing applications for licenses. The new Directorate of Regul atory Standards would consolidate all AEC activities in the development of standards for powerplants, other facilities, and for the use of radioactive
materials.
274

27 5

The deputy director for fuels and materials was
assigned the responsibility to manage those mattersconcerning licenses to utilize radioactive materials
for all purposes other than commercial power production.
A third major directorate, that for regulatory
operations, was created to consolidate the AEC'sli censee inspection and enforcement program previously contained in several divisions. Within thisdirectorate, the Office of Operations Evaluation wasestablished "to collect and evaluate data on licensee
operations, and to provide
feedback to the licensingiand standards efforts."
The Directorate of Licensing organization
remained essentially constant throughout 1973 and1974. Eighteen new CP applications were received
i n 1973, more than four times the number received
i n either 1971 or 1972. 2 The Division of Technical
Review was 40% larger at the end of 1973 than ayear earlier. The project management assistantdirectorates increased by about 14% in the sameti me.
Two reactor units similar to the TMI units received operating licenses during 1973. Oconee 1
and 2, constructed and operated by the DukePower Company, commenced operation on Lake
Keowee in South Carolina. The TMI-1 plant received
an operating license in April 1974. Oconee 3, also
at the Lake Keowee site, began operation in July
1974.
I n early 1973, Dixie Lee Ray became Chairman of
the AEC. During 1974, the final separation of the regulatory and promotional organizations within AEC
were debated by the Congress in developing what
would become the Energy Reorganization Act of1974. Also during this year the TMI-2 operating
li cense application was tendered and finally accepted for review on April 4,1974.

headed by Muntzing, became five offices under an
executive director for operations. Three of the offices were authorized to interact directly with theCommission when deemed necessary: the Officesof . Nuclear Reactor Regulation, Nuclear Materials
Safety and Safeguards, and Nuclear Regulatory
Research. An Office of Inspection and Enforcement
was assigned the responsibility formerly assigned to
the Directorate of Regulatory Operations. An Officeof Regulatory Standards paralleled the former
Directorate of Regulatory Standards.
By May 1975, Benard C. Rusche had taken theposition of director, Office of Nuclear Reactor Regulation (NRR), which was roughly equivalent to theformer Directorate of Licensing. This office wascomprised of the Division of Reactor Licensing andthe Division of Technical Review, entities whichwere identical to those 1974 (AEC) organizations
under the deputy director for reactor projects andthe deputy director for technical review, respectively. App. Figure 1-3 shows the May 1975 NRR organization, which can be compared to the earlier organization shown in App. Figure 1-2.
By June 1975, the position of director, Division ofTechnical Review was accepted by Dr. Robert
Heineman_ The position had been vacant for about
1 year following Dr. Joseph Hendrie's resignation. In
December 1975, Rusche announced an expansion
and realignment of NRR. The organization, shown inApp. Figure 1-4, would now have four divisions instead of two, giving new emphasis to regulatory
matters involving operating reactors, and to the review and evaluation of safety and environmental aspects of reactor sites. In describing the new organization, Rusche noted' an improved management
structure, more efficient site safety and environmental reviews, and "...improved feedback of operating
experience into licensing requirements and decisions." The new Division of Operating Reactors,
directed by Victor Stello, Jr., was created in part to"... analyze and respond to operating experiences
as they develop and assure that current experiencei s factored into new licensing actions." 3
The new Division of Site Safety and Environmental Analysis was directed by Harold Denton.
Throughout the remainder of 1976, 1977, and1978, the organization structure remained essentially the same, with several key changes in personnel
and the addition of an Assistant Directorate for
Reactor Safeguards within the Division of Operating
Reactors. In April 1977, Rusche resigned, and Edson Case became the acting Director of NRR until
July 1978 when Denton took that position. Roger
Mattson became the new Director, Division of Systems Safety in July 1977.

Staff Organization, January 1974 to February 1978

The organization during 1973 and 1974 wasessentially constant, and as previously described.
On January 18, 1975, the AEC was abolished by the
Energy Reorganization Act of 1974, and replaced by
the Nuclear Regulatory Commission (NRC) and theEnergy Research and Development Administration( ERDA).
A former AEC Commissioner, William Anders, became Chairman of the NRC. The other four NRC
commissioners were new appointees, including
Marcus Rowden, former AEC General Counsel, who
would later become NRC Chairman. The three
directorates, which in 1974 were the line operatingorganizations in the AEC's regulatory organization
277

27 8

REFERENCES AND NOTES
NRC, "Program Summary Report," Volume 3, No. 4,
NUREG-0380, April 20, 1979.
3
NRC Public Annoucement No. 75-284.

'AEC Public Announcement, "AEC Announces Major
Reorganization of its Regulatory Staff," release no. P-118,
Tuesday, April 25, 1972.

2

28 0

APPENDIX 1.5

THE STANDARD REVIEW PLAN
(This Appendix is taken in entirety from the Introduction to the Standard Review Plan, Revision 1,
issued in November 1978)

operate such a facility shall include a Final Safety
Analysis Report. The SAR must be sufficiently
detailed to permit the staff to determine whether theplant can be built and operated without undue risk
to the health and safety of the public. Prior to submission of an SAR, an applicant should havedesigned and analyzed the plant in sufficient detail
to conclude that it can be built and operated safely.
The SAR is the principal document in which theapplicant provides the information needed to understand the basis upon which this conclusion has
been reached.
Section 50.34 specifies, in general terms, thei nformation to be supplied in an SAR. The specifici nformation required by the staff for an evaluation ofan application is identified in Regulatory Guide 1.70,"Standard Format and Content of Safety Analysis
Reports for Nuclear Power Plants-LWR Edition."
The SRP sections are keyed to the Standard Fomat, and the SRP sections are numbered according
to the section numbers in the Standard Format.
Review plans have not been prepared for SAR sections that consist of background or design data thatare included for information or for use in the review
of other SAR sections.
The Standard Review Plan is written so as tocover a variety of site conditions and plant designs.
Each section is written to provide the complete procedure and all acceptance criteria for all of the"The Standard Review Plan for the Review of
Safety Analysis Reports for Nuclear Power Plants,
LWR Edition," NUREG-75/087, was issued on
November 24,1975, and revised in March 1979.
The Standard Review Plan (SRP) is prepared forthe guidance of staff reviewers in the Office of
Nuclear Reactor Regulation in performing safety
reviews of applications to construct or operate
nuclear powerplants. The principal purpose of the
SRP is to assure the quality and uniformity of staff
reviews, and to present a well-defined base fromwhich to evaluate proposed changes in the scopeand requirements of reviews. It is also a purpose of
the SRP to make information about regulatory
matters widely available and to improve communication and understanding of the staff review process
by interested members of the public and the nuclear
power industry.
The safety review is primarily based on the information provided by an applicant in a Safety Analysis
Report (SAR). Section 50.34 of 10 CFR Part 50 of
the Commission's regulations requires that eachapplication for a construction permit for a nuclear
facility shall include a Preliminary Safety Analysis
Report and that each application for a license to281

areas of review pertinent to that section. However,for any given application, the staff reviewers may
select and emphasize particular aspects of each
SRP section as is appropriate for the application. In
some cases, the major portion of the review of aplant feature may be done on a generic basis withthe designer of that feature rather than in the context of reviews of particular applications from utilities. In other cases, a plant feature may be sufficiently similiar to that of a previous plant so that a
de novo review of the feature is not needed. For
these and other similar reasons, the staff may notcarry out in detail all of the review steps in each
SRP section in the review of every application.
The individual SRP sections address, in detail,who performs the review, the matters that are
reviewed, the basis for review, how the review isaccomplished, and the conclusions that are sought.
The safety review is performed by 18 branches.
One of the objectives of the SRP is to assign thereview responsibilities to the various branches andto define the sometimes complex interfaces
between them. Each SRP section identifies thebranch that has the primary review responsibility forthat section. In some review areas the primarybranch may require support and the branches thatare assigned these secondary review responsibilities are also identified for each SRP section.
Each SRP is organized into four subsections asfollows:

or Appendices which are included in the SRP.
These documents typically set forth the solutions
and approaches determined to be acceptable in
the past by the staff in dealing with a specificsafety problem or safety-related design area.
These solutions and approaches are codified inthis form so that staff reviewers can take uniform
and well-understood positions as the same
safety problems arise in future cases. Some
Branch Technical Positions and Appendices may
be converted into Regulatory Guides if it appears
that this step would aid the review process. Like
Regulatory Guides, the Branch Technical Positions and Appendices represent solutions andapproaches that are acceptable to the staff, butthey are not required as the only possible solutions of approaches. However, it should berecognized that, as in the case of Regulatory
Guides, substantial time and effort on the part ofthe staff has gone into the development of the
Branch Technical Positions and Appendices andthat a corresponding amount of time and effort
will probably be required to review and accept
new or different solutions and approaches. Thus,
applications proposing other solutions andapproaches to safety problems or safety-related
design areas than those described in the Branch
Technical Positions and Appendices must expect
longer review times and more extensive questioning in these areas. The staff is willing to consider proposals for other solutions andapproaches on a generic basis, apart from a
specific license application, to avoid the impact of
the additional review time on individual cases.
Ill. Review ProceduresThis subsection discusses how the review isaccomplished. The section is generally a stepby-step procedure that the reviewer goes
through to provide reasonable verification thatthe applicable safety criteria have been met.
I V. Evaluation Findings
This subsection presents the type of conclusionthat is sought for the particular review area. For
each section, a conclusion of this type is included
i n the staff's SER in which the staff publishes theresults of their review. The SER also contains a
description of the review including such subjects
as which aspects of the review were selected oremphasized; which matters were modified by theapplicant, require additional information, will be
resolved in the future, or remain unresolved;
where the plant's design or the applicant's programs deviate from the criteria stated in the SRP;
and the bases for any deviations from the SRP or
exemptions from the regulations.

I. Areas of Review
This subsection describes the scope of review
i. e., what is being reviewed by the branch having
primary review responsibility. This subsection
contains a description of the systems, components, analyses, data, or other information thatis reviewed as part of the particular SAR section
i n question. It also contains a discussion of thei nformation needed or the review expected fromother branches to permit the primary review
branch to complete its review.
II. Acceptance Criteria
This subsection contains a statement of the purpose of the review and the technical basis fordetermining the acceptability of the design or the
programs within the scope of the area of reviewof the SRP section. The technical bases consistof specific criteria such as NRC Regulatory
Guides, General Design Criteria, Codes and Standards, Branch Technical Positions, and other criteria.
The technical bases for some sections of the
SRP are provided in Branch Technical Positions

282

APPENDIX 1.6

ACRS LETTER OCTOBER 22, 1976
ADVISORY COMMITTEE ON REACTOR SAFEGUARDS
Nuclear Regulatory Commission
Washington, D.C.
October 22,1976
Honorable Marcus A. Rowden
ChairmanU.S. Nuclear Regulatory Commission
Washington, D.C. 20555

SUBJECT: REPORT ON THREE MILE ISLAND NUCLEAR STATION, UNIT 2
Dear Mr. Rowden:

During its 198th meeting, October 14-16,1976, the Advisory Committee on Reactor
Safeguards completed its review of the application of the Metropolitan Edison
Company, Jersey Central Power and Light Company, and Pennsylvania ElectricCompany (Applicants) for a license to operate Three Mile Island Nuclear Station,
Unit 2. This project was also considered during a Subcommittee meeting held inHarrisburg, Pennsylvania, on September 23 and 24,1976. Members of theCommittee visited the facility on September 23, 1976. During its review, theCommittee had the benefit of discussions with representatives and consultants of
the Applicants, General Public Utilities Service Corporation, the Babcock andWilcox Company (B&W), Burns and Rowe, Inc., and the Nuclear Regulatory
Commission (NRC) Staff. The Committee reported on the application for aconstruction permit for Unit 1 on January 17 and April 12,1968, and for an
operating license for Unit 1 on August 14, 1973. The Committee reported on theapplication for a construction permit for Unit 2 on July 17,1969.
283

The Three Mile Island Nuclear Station, Units 1 and 2, is located on Three Mile
Island near the eastern shore of the Susquehanna River, about 12 miles southeastof Harrisburg, Pennsylvania. About 2380 people live within a two-mile radius of
the site (the low population zone). The minimum exclusion distance is 2000 feet.
The nearest population center is Harrisburg (1970 population 68,000).
Several changes have been made to bring the Babcock and Wilcox Emergency
Core Cooling System (ECCS) evaluation model into conformance with therequirements of 10 CFR 50.46, and Appendix K to Part 50. Analyses of aspectrum of break sizes appropriate to Three Mile Island, Unit 2 have been
completed using the approved B&W generic evaluation model. The results of theanalyses for the reactor coolant pump discharge break, believed to be the "worst"
break, show maximum allowable linear heat generation rates as a function ofelevation in the reactor core ranging from 15.5 to 18.0 kilowatts per foot.
Corresponding calculated post-accident peak clad temperatures range from2002°F to 214°F. The NRC Staff has identified additional information that it will
require to complete its review and the Applicants' submittal is expected by the endof 1976. The Applicants propose to use both in-core and ex-core instrumentation
to assure accuracy of measurement of core power distributions. The Committee
believes that the proposed monitoring methods may be acceptable, but that anaugmented startup program should be employed, and that satisfactory experienceat 100% steady state power and during transients at less than full power should beobtained. This experience should be reviewed and evaluated by the NRC Staff
prior to operating at up to full power in a load following mode. The Committee
wishes to be kept informed.
A question has arisen concerning asymmetric loads on the reactor vessel and its
internal structures for certain postulated loss-of-coolant accidents in pressurizedwater reactors. The Staff has required the Applicants to supply further informationin order to complete its assessment of this matter. This issue should be resolvedin a manner satisfactory to the NRC Staff.
The question of whether Unit 2 requires design modifications in order to comply
with WASH-1270, "Technical Report on Anticipated Transients Without Scram for
Water-Cooled Power Reactors", remains an outstanding issue pending the NRC
Staff's completion of its review of B&W generic analyses of anticipated transients
without scram. The Committee recommends that the NRC Staff, the Applicantsand B&W continue to strive for an early resolution of this matter in a manner
acceptable to the NRC Staff. The Committee wishes to be kept informed.
Emergency plans have been developed to allow plant shutdown and maintenanceof safe shutdown in the event of a maximum probable flood. Such a postulated
flood would top the levee surrounding the plant by several feet. Included in theplan is the fastening of water tight steel panels in doorways and other openings ofsafety related structures. The Committee believes that the details of this plan,
particularly relating to re-entry into the station during the post-flood period, need
to be more clearly delineated.
The Committee supports the NRC Staff's program for evaluation of fire protection
i n accordance with Branch Technical Position APCSB 9.5-1, Appendix A," Guidelines for Fire Protection for Nuclear Power Plants". The Committee
recommends that the NRC Staff give high priority to the completion of both ownerand Staff evaluations and to recommendations for Three Mile Island Unit 2 andother plants nearing completion of construction in order to maximize theopportunity for improving fire protection while areas are still accessible andchanges are more feasible.
284

The Committee notes that long-term post-accident operation of the plant tomaintain safe shutdown conditions may be dependent on instrumentation andelectrical equipment within containment which is susceptible to ingress of steam orwater if the hermetic seals are either initially defective or should become defective
as a result of damage or aging. The Committee believes that appropriate test
procedures to confirm continuous long-term seal capability should be developed.
The Committee recommends that further review be made of the battery supplied
DC power system to assure that non-essential loads do not interfere with its
safety function. The Committee recommends that further review be made toassure no unacceptable effects such as release of hydrogen into the plant canoccur from the failure of a hydrogen charging line. The Committee also
recommends that studies be made to assure that failure of an instrument line
cannot cause plant controllability problems of significance to public safety.
The management organization proposed by the Applicants to delineate the safety
related responsibilities of the off-site and on-site personnel of the Three Mile
Island Station left open questions as to how these responsibilities are to bedischarged during normal working hours and during evening, night, and weekend
shifts. This matter should be resolved to the satisfaction of the NRC Staff.
The NRC Staff is still reviewing various issues related to accidents leading to lossof fluid in the steam generator secondary side, such as steam line breaks. The
Committee wishes to be kept informed of the resolution of these issues.
The Committee recommends that, prior to commercial power operation of Three
Mile Island Unit 2, additional means for evaluating the cause and likely course ofvarious accidents, including those of very low probability should be in hand inorder to provide improved bases for timely decisions concerning possible off-site
emergency measures. The Committee wishes to be kept informed.
The Committee believes that the Applicants and the NRC Staff should further
review the Three Mile Island Nuclear Station for measures that could significantly
reduce the possibility and consequences of sabotage, and that such measures
should be implemented where practical.

Other generic problems relating to large water reactors are discussed in theCommittee's report entitled "Status of Generic Items Relating to Light Water
Reactors: Report No. 4", dated April 16,1976. Those problems relevant to theThree Mile Island Station should be dealt with appropriately by the NRC Staff and
the Applicants as solutions are found. The relevant items are: II - 1, 2, 3, 4, 5, 6,
7, 9, 11; IIA - 1, 4, 5, 6, 7, 8; IIC - 1, 2, 3, 4, 5, 6, 7.
The Advisory Committee on Reactor Safeguards believes that, if due regard isgiven to the items mentioned above, and subject to satisfactory completion of
construction and pre-operational testing, there is reasonable assurance that Three
Mile Island Nuclear Station, Unit 2 can be operated at power levels up to 2772
MWt without undue risk to the health and safety of the people.
Sincerely yours,

Dade W. Moeller
Chairman285

References

1. Three Mile Island Nuclear Station, Unit 2 Final Safety Analysis Report (April,
1974) with Amendments 1 through 44.
2. Safety Evaluation Report (NUREG-0107) related to operation of Three MileI sland Nuclear Station, Unit 2, dated September, 1976.

286

APPENDIX 1.7

EXTRACTS FROM ADJUDICATORYDECISIONS-THREE MILE ISLANDNUCLEAR STATION UNIT2
DOCKET NO. 50-320
I N THE MATTER OF JERSEY CENTRAL POWER & LIGHT
COMPANY AND METROPOLITAN EDISON COMPANY(THREE MILE ISLAND NUCLEAR STATION, UNIT 2)

I ssued November 12, 1969
(4 AEC Reports 283)
I NITIAL DECISIONPRELIMINARY STATEMENT
1. This proceeding involves the application of
Jersey Central Power & Light Company and Metropolitan Edison Company (Applicants) for a provisional construction permit to construct a pressur-i zed water reactor designed for initial operation atcore power levels up to 2,452 megawatts (thermal).
The facility, designated as Three Mile Island Nuclear
Station Unit 2, (hereinafter, Unit 2) will be located on287

a site at Three Mile Island adjacent to Unit 1, a
nuclear electric generating plant which is now underconstruction by Metropolitan Edison Company. Thei sland site in the Susquehanna River is in Dauphin
County about 10 miles southeast of Harrisburg,
Pennsylvania. The application has been reviewed
by the Regulatory Staff (Staff) of the Atomic Energy
Commission (Commission) and the Advisory Committee on Reactor Safeguards (ACRS), both ofwhich concluded that there is reasonable assurance
that the described facility can be constructed andoperated at the proposed site without undue risk to
the health and safety of the public.
2. In accordance with the requirements of theAtomic Energy Act and the Commission's regulations, and pursuant to the notice of Hearing publi shed in the Federal Register on August 27,1969, at
34 Fed. Reg. 13708, a public hearing was held
before this Atomic Safety and Licensing Board(Board) on October 6,1969, in Middletown, Pennsylvania, to consider whether a provisional construction permit should be issued to the Applicants. The
parties to the proceeding were the Applicants andthe Staff. No petitions for leave to intervene werefiled.
Pursuant to Section 2.715(a) of theCommission's Rules of Practice, Dr. Arthur Socolow,
an area resident who attended throughout the hear-i ng, presented a limited appearance statement
expressing concern relating to protection of the
facility from aircraft using the nearby Olmstead
State Airport. Mr. Thomas M. Gerusky, representi ng the Pennsylvania Department of Health, statedthat mutually satisfactory programs relating to radiol ogical health and emergency procedures had been
established in cooperation with the Applicants andthe U.S. Public Health Service. Subsequent to thehearing proposed findings and conclusions werefiled by the Applicants and the Staff.
3. This is not a contested proceeding as defined
i n Section 2.4(n) of the Commission's Rules of Practice. Accordingly, the Board is instructed by theRules and in the Notice of Hearing to consider thei ssues of whether the application and the record of
the proceeding contain sufficient information, andthe review by the Staff has been adequate to support the findings proposed to be made and the provisional constructional permit proposed to be issued
by the Director of Regulation. The findings and thepermit proposed by the Director of Regulation were
published in and with the Notice of Hearing. The
post-hearing pleadings of the parties propose affirmative conclusions upon the issues: they are supported by and in accordance with the reliable, probative, and substantial evidence in the record.

FINDINGS OF FACT
4. Jersey Central Power & Light Company andMetropolitan Edison Company will share the financing and ownership of Unit 2 in the ratios of 25 percent and 75 percent, respectively. Each of the
Applicants is an operating utility engaged in the generation, transmission and sale of electric power.
The Applicants are two of four wholly-owned subsidiaries of General Public Utilities Corporation (GPU),a Pennsylvania corporation registered under the
Public Utility Holding Company Act of 1935. Each of
the Applicants is financially sound and plans tofinance its share of the costs of construction of the
proposed facility as part of its overall construction
program. Funds to meet construction requirements
will be provided by internal sources and capital contributions from GPU and by the sale of debt securities in such a manner as to maintain a sound andconservative capital structure.
5. Metropolitan Edison Company is responsible
for engineering, design, construction, operation andmaintenance of Unit 2. Metropolitan Edison Company has 85 years' experience in the design, construction, and operation of electric generating stations, and is now constructing Three Mile Island

Nuclear Station Unit 1. The GPU Nuclear Power
Activities Group, with nuclear experience in operating power reactors at Saxton and Oyster Creek, will
provide technical assistance and guidance to theThree Mile Island Project Director, John G. Miller,
who is Vice President and Chief Engineer of Metropolitan Edison Company. The nuclear steam supply
system is being designed and fabricated by the
Babcock & Wilcox Company. Burns and Roe, Inc.,
has been engaged as the project architect-engineer
except in the areas of cooling tower design andinterfaces between Unit 1 and Unit 2 for which Gilbert Associates, Inc., has been engaged. United
Engineers and Constructors, Inc., is the construction
manager for both Unit 1 and Unit 2. Applicants will
rely also on assistance in design, quality assurance,and structures to be provided by Pickard & Lowe
Associates, MPR Associates, and Schupack &Associates. The record supports the Staff's conclusion that "the applicants are technically qualified
to design and build the Three Mile Island Nuclear
Station Unit 2".
6. The Unit 2 reactor will operate initially at core
powers up to 2,452 Mwt and is designed for an288

expected ultimate capacity of 2,772 Mwt. Thishigher power has been used as the design basis forthe containment and the engineered safety features,and it has been used by the Staff and the Applicants in the accident analyses and in the evaluationof all major structures, systems, and components
which bear significantly on the acceptability of thesite. The exclusion distance for the Three Mile
Island site is 2,000 feet. Based upon the combined
population of the Middletown-Steelton communities(22,450) with their nearest boundary at 2.2 miles,
the Applicants have proposed a low population zone
radius of two miles. The plant design will take into
account local hydrological conditions, earthquakes,
tornados, and possible aircraft impacts. The Applicants will provide protection against the Probable
Maximum Flood (PMF) as calculated by the Corps ofEngineers.
7. A comprehensive pre-operational environmental monitoring program has been in progress at
this site for some time in connection with the Three
Mile Island Unit 1. The Applicants will continue tocooperate with interested government agencies
concerning radiological surveys and in accordancewith recommendations of the Fish and Wildlife Service. This record includes evidence from the Applicants and Staff which indicates that theSusquehanna River basin as well as the Chesapeake Bay can accommodate the installation of the
proposed plant and an additional number of othersuch plants without causing total or cumulative concentrations of radiological effluents to exceed morethan a small fraction of the values set forth in 10
CFR Part 20.
8. The proposed facility incorporates numerous
systems, components and features for the protection of plant personnel and the public and is similari n design to plants incorporating pressurized water
reactors which have been previously approved forconstruction by the Commission. An importantsafety feature is the containment system which willcompletely enclose the reactor and major components of the primary coolant system. The containment system consists of a reinforced prestressed concrete structure with a vapor tight steel
li ner. The prestressed tendons will be grouted toprovide protection against corrosion. The containment structure is designed to accommodate, without
loss of integrity, functional loads resulting from aloss-of-coolant accident occurring simultaneouslywith the maximum hypothetical earthquake and normal operating loads.
9. The proposed facility has two separable cooli ng systems which assure adequate core coolingand pressure reduction within the containment

structure even if a loss-of-coolant accident should
occur. For immediate short-term cooling, an emergency core cooling system will inject cool borated
water into each of the primary coolant loops anddirectly into the reactor vessel, thereby limiting thefuel pin clad temperatures and fission productrelease into the containment. For cooling containment air to reduce the containment vessel internalpressure in the unlikely event of a major accident,
there are two independent spray systems which
deliver cool borated water into the containment
atmosphere. These systems will provide borated
water containing dissolved sodium thiosulphate andsodium hydroxide to remove iodine in the event ofan accident.
10. The Applicants and the Staff recognize thati n order to develop the final design of the facility
further information and data will be needed. Suchadditional information and data will be developed byresearch and development projects in the course of
the final design work for the plant. In addition, basic
work in progress is expected to provide some confirmation that the proposed designs are conservative. The major areas of research and developmenti nclude the xenon oscillations, core thermal andhydraulic tests, fuel rod clad failure, high burnup fueltests, internal vent valves, control rod drive test,
once-through steam generator, in-core neutron
detector test, blowdown forces on reactor internals,
chemical spray system, and effects of radiolysis.
The objectives of these programs have been
defined, and a schedule for the furnishing of information prior to completion of construction of the
proposed facility has been established.
11. Applicants have established a comprehensive
quality assurance program which is consistent with
the intent of, and which has been evaluated by the
Staff in accordance with, the AEC's "Quality
Assurance Criteria for Nuclear Power Plants" which
was recently published as a proposed Appendix B
to 10 CFR Part 50. Applicants' quality assuranceorganization, including the GPU Manager of Quality
Assurance, will undertake to assure that the facility
will be fabricated and constructed in accordancewith applicable codes and specifications. The quality assurance program encompasses overall direction, guidance and surveillance over the quality
assurance practices to be observed by the reactor
supplier, the architect-engineer, the construction
manager, and their subcontractors.
12. The facility will be located 2 '/2 miles from
Olmstead State Airport. Although the probability of
an aircraft incident at the Three Mile Island Nuclear
Station is remote, the vital structures of the station
will be designed to withstand a significant range of289

aircraft strike loadings, including such secondary
effects as missiles, fire, pressure and temperature.
Dr. Socolow's statement inquired about the capability of the containment building and other criticalcomponents to withstand an impact of a larger thanthe design basis aircraft (200,000 lbs.). The
responsive evidence presented by the parties, inaddition to that concerning the low probability of
impact, is persuasive that there is little likelihoodthat any aircraft impact on the facility could cause
the release of radioactivity. This view rests upon an
evaluation of the conservative design of the containment to withstand impact, and the value of the additional protection provided to the reactor and the primary cooling system by shield walls inside the containment. In addition, under adverse weather conditions involving poor visibility, landings by all large
aircraft using Olmstead Airport would be underi nstrument flight regulations which then would not
permit flights over the site.
13. The activities to be conducted under the provisional construction permit will be within the jurisdiction of the United States, and all of the directors
and principal officers of the Applicants are UnitedStates citizens. The Applicants are not owned, controlled or dominated by an alien, a foreign corporation or a foreign government. The activities to be
conducted do not involve any restricted data, but
the Applicants have agreed to safeguard any suchdata which might become involved in accordancewith 10 CFR Part 50.33(j). Special nuclear material
for use as fuel in the proposed facility will be subject to Commission regulations and will be obtained
from sources of supply such that there will be nodiversion of such material to unauthorized uses.

CONCLUSIONS
14. Upon consideration of the entire record inthis proceeding and the findings of fact and statements set forth above, the Board concludes that theapplication and the record of the proceeding containsufficient information, and the review of the applica-tion by the Staff has been adequate to support thefindings proposed to be made by the Director ofRegulation, and the issuance of the provisional construction permit as proposed by the Director ofRegulation.

ORDER
Pursuant to the Act and the Commission's regul ations, IT IS ORDERED that the Director of Regulation issue a provisional construction permit to theJersey Central Power and Light Company and theMetropolitan Edison Company substantially in theform set forth in Appendix "A" to the Notice of Heari ng in this proceeding.
I T IS FURTHER ORDERED, in accordance with 10
CFR Section 2.760, 2.762 and 2.764 of theCommission's Rules of Practice, that this Initial Decision shall be effective immediately and shall consti-

tute the final action of the Commission 45 days after
the date of issuance, subject to the review thereof
and further decision of the Commission upon its
own motion or upon exceptions filed pursuant to thecited rules.
ATOMIC SAFETY AND LICENSING BOARD,
CLARKE WILLIAMS,
ABEL WOLMAN,
J. D. BOND, CHAIRMAN.

290

Cite as 6 NRC 1185 (1977)
UNITED STATES OF AMERICA
NUCLEAR REGULATORY COMMISSIONLBP-77-70

ATOMIC SAFETY AND LICENSING BOARD
Edward Luton, Chairman
Ernest O. Salo
Gustave A. Linenberger
I n the Matter of
METROPOLITAN EDISON COMPANY
JERSEY CENTRAL POWER &LIGHT COMPANYPENNSYLVANIA ELECTRIC
COMPANY(Three Mile Island Nuclear Station,
Unit no. 2)DocketNo. 50-320

December 19. 1977
I. INTRODUCTION

1. This is a proceeding on the application of
Metropolitan Edison Company, the Jersey Central
Power and Light Company, and the Pennsylvania
Electric Company ("Applicants") for licenses to construct and operate the Three Mile Island Nuclear
Station, Unit No. 2 ("TMI-2"). The plant is locatedadjacent to a similar unit (Three Mile Island Nuclear
Station, Unit No. 1) on Three Mile Island in theSusquehanna River in Londonderry Township, Dauphin County, Pennsylvania.
2. Construction of TMI-2 was authorized on
November 4, 1969. By application dated April 4,
1974, Applicants requested authorization, pursuant
to Section 104.b of the Atomic Energy Act of 1954,
as amended, to possess, use, and operate TMI-2, apressurized water nuclear reactor, at a steady state
power level of 2,772 megawatts thermal. On May
20, 1974, the Commission issued a notice which
provided that any person whose interest might beaffected by the proceeding could file a request for a
public hearing in the form of a petition to intervene
i n accordance with the Commission's regulations
contained at 10 CFR Section 2.714. Petitions toi ntervene were received from the Citizens for a Safe
Environment and the York Committee for a Safe
Environment (as "joint petitioners"), and from Mrs.
Barbara Pradel of Greencastle, Pennsylvania. Additionally, the Commonwealth of Pennsylvania
requested leave to participate as an interested State
pursuant to 10 CFR Section 2.715(c). On July 24,
1974, the Atomic Safety and Licensing Board designated to rule on intervention requests granted thejoint petitioners' request to intervene, granted theCommonwealth's request to participate, and denied1
the intervention petition of Mrs. Barbara Pradel.
3. This Atomic Safety and Licensing Board("Board") has conducted a public evidentiary hearing
to consider (1) issuance or denial of a full-term
operating license for TMI-2 or its appropriate conditoning to protect environmental values and (2)because TMI-2 is subject to the provisions of Section C of Appendix D of 10 CFR Part 50, whether
considering those matters covered by Appendix D,
the provisional construction permit for TMI-2 should
be continued, modified, terminated, or appropriately
conditioned to protect environmental values. With
respect to its consideration under Appendix D of theTMI-2 construction permit, the Board has conducted a full NEPA review covering both contested
and uncontested environmental matters. With
respect to the operating license the Board has, inaccordancewith
Section2.760aof theCommission's Rules of Practice, confined its findi ngs to the matters in controversy. 2
4. The Board has considered the entire recordof this proceeding and all of the proposed findingsof fact and conclusions of law submitted by the parties. All proposed findings and conclusions submitted by the parties which are not incorporated
directly or inferentially in this initial decision are
rejected as being unsupported in law or in fact, oras being unnecessary to the rendering of this decision.
291

Contention 5

II. FINDINGS OF FACTof the public, absent an analysis of theconsequences of such an impact?
iii) Are the current and anticipated frequenciesof heavy aircraft operations at the Harrisburg Airport properly taken into account?

The containment structure and other buildings
designed to withstand certain aircraft impact events
are of inadequate strength to withstand the impactof airplanes which can reasonably be expected tofrequent Harrisburg International Airport. Both the
Boeing 747 and the Lockheed C-5A are reasonably
expected to frequent Harrisburg International Airportand greatly exceed the kinetic energy set for thedesign consideration.
38. The Board views this Contention as, in
effect, comprising the following two allegations:

The Board considers it appropriate to resolve Item(b) via these subissues.
42. The probability computation (Item (b)(i)above) is addressed first. The Applicants have calculated a probability of about 3x10 -9 events per
year, per unit, for aircraft larger than 200 thousand
pounds, based upon Harrisburg International Airport
data that yielded an estimate for 1976 of approximately 511 operations (takeoffs or landings) of suchplanes, using those runways that could require aflight pattern imposing a potential threat to TMI-2.
This result includes all strikes upon any structure,i rrespective of whether there is disabling damage
leading to shutdown; it disregards the angle ofstrike; and, further, it disregards any protective
shielding effect from the cooling towers and othernoncritical structures.
Finally, the Applicants'
analytical approach incorporates an angular correlation consideration that results in a decrease of
strike probability for planes whose approaches lie
along lines displaced at increasing angles from theextended runway centerline (Vallance, loc. cit.).
43. According to the testimony of Vallance, theStaff assumed for the sake of conservatism that the
TMI Station lies within (although it is slightly outsideof) a 60 degree sector centered on the runway
centerline, and that all strike locations are equallyprobable within that sector. Using otherwise similargeometry and flight frequency assumptions, theStaff, per Valiance's testimony, has obtained a probability of 10" 7 events per year, per unit (Vallance,
loc.cit.). The Staff's witness stated the Staff's conclusions as follows:(a) A first allegation that claims that critical (safety
Category I) structures are not capable of withstanding the impact of the Boeing 747 and the
Lockheed C-5A aircraft.
(b)A second and follow-on allegation that these
two types of aircraft will potentially use theHarrisburg International Airport with sufficientfrequency to generate more than a de minimus
concern for the health and safety of the public.

39. The Applicants and the Staff both presented
prepared testimony and proposed findings on thisContention (testimony of Applicants' Witness J. M.
Vallance, following Tr. 511; testimony of Staff's Witness J. B. J. Read, following Tr. 617; supplemental
testimony of Read, following Tr. 1297). The Joint
I ntervenors relied on cross-examination of the
Applicants' and Staff's witnesses and upon argument presented in their proposed findings.
40. The evidence is that the TMI-2 facility is notcapable of withstanding the impact of an aircraft
weighing in excess of 200,000 pounds. In addition,
the Boeing 747 and the Lockheed C-5A, in flight at
200 knots or greater velocity, each has a kinetic
energy that exceeds the impact resistance forwhich the TMI-2 structures (particularly the containment) are designed to withstand (Vallance, cited
above). The Board thus finds that Item (a) is acorrect statement of fact.
41. The follow-on allegation, Item (b) above,reflects the remaining substantive issue within thisContention. The nature of the direct testimony andthe scope of the Joint Intervenors' crossexamination prompts the Board to, in effect, subdivide Item (b) into three subissues:

The staff (sic) has concluded that, with respect to
the TMI-2 site, the risk from aircraft is acceptably
l ow if fewer than 2400 operations per year at Harrisburg International Airport are flown by aircraftl arger than the design basis aircraft. The basis forthis conclusion is that the expectation of aircraft
larger than the Boeing
720 striking the plant would
7
then be less 10" per year (estimated by the algorithm contained in Standard Review Plan Section
3.5.1.6, NUREG-75/087 (September 1975)). At
present, about 600 four-engine jets per year use
the airport, which is considerably within our criterion of 2400.

i) Has the computation of the probability of anaircraft impact been properly carried out?
ii) If so, is the result adequate to justify anegligible concern for the health and safety(Testimony of J. B. J. Read, following Tr. 617.)
44. The Board here interprets the above quoted
airport usage of "600 four-engine jets per year" to
29 2

be consistent with the Applicants' value of 511
operations per year. The two different probability
results are judged by the Board to be compatible inthe sense that the difference between them is plausible, based upon the cited assumptions regarding
conservatism. The Board finds that the probability
assessments have been properly carried out.
45. The Joint Intervenors, as the result ofcross-examination, have submitted proposed findi ngs that challenge the validity of the computationalmodel used by the Applicants and by the Staff, criticize the lack of "peer review" given to the model,
and question its applicability of the results. After acareful weighing of the cross-examination and theresults of our own examination of the witnesses, theBoard finds that, while certain of the Intervenors'
proposed findings are literally true, none of them
represents a significant flaw in the adequacy andapplicability of the strike probability results. Nor
were the competence and judgments of the twowitnesses impugned to any significant extent. We
find to be acceptable and conservative the resultthat the probability of an impact of any nature onsome portion of the TMI-2 facility by a heavier than
200 thousand-pound aircraft is currently less than-7
10 per year, under the various qualifying conditions imposed.
46. Item (b)(ii) is addressed next. Regarding thehealth and safety of the public, neither the Applicants nor the Staff refuted the concern of the Joint
Intervenors that the impact of a plane weighing morethan 200 thousand pounds into a safety Category I
structure might give rise to radiological consequences greater than the exposure guidelines of 10
CFR Part 100. This concern, in turn, prompted the
I ntervenors to file a motion to compel the appearance of a witness to discuss the consequences ofsuch an event (nature and disposition of this motion
discussed below).
47. Applicants' witness and counsel for the Staff
appealed to the guideline probability values set forthi n NUREG-75/087 (in particular, Section 3.5.1.6,
AIRCRAFT HAZARDS), whereby an analysis ofconsequences is not required if, as here, the probabili ty assessment yields a value of less than 10 -7 per
year. The Staff's witness, in response to Board
questions, indicated that in his professional judgment consequences are not entirely ignored by the
10-7 probability guideline. If, for example, the consequences were so severe as to threaten a monumental loss of life or property, a different approach
would be taken before deciding whether to permit
plant operation (Tr. 673-675).
48. Irrespective of the foregoing, the Joint Intervenors at various times during the course of thehearing requested that the Applicants and the Staff
provide witnesses to discuss the consequences ofan accident caused by a larger than 200 thousandpound aircraft colliding with the facility (Tr.
590-600, 615-616, 621, 632-650, 713). By written
motion dated April 15, 1977, Joint Intervenors sought
to have this Board compel the Applicants to produce witnesses on such consequences. We denied
that motion orally at the evidentiary hearing on May
18, 1977 (Tr. 1549). On August 8, 1977, we set out
in writing the basis for that denial. We there took
the position that under the Commission's scheme of
regulation, Applicants need not be concerned withthe consequences of extremely improbable accident
events (less than 10 -7 per year) such as we findhere. We adhere to that view for the reasons statedi n our Order of August 8.
49. We turn now to the frequency of heavy aircraft operations (Item (b)(iii) above). As noted
above, the Applicants have established that for 1976
about 511 heavy (200 thousand pounds or greater)
aircraft used the Harrisburg International Airport in
those flight patterns that could potentially pose athreat to the TMI-2 facility. This corresponds to one
to two operations per day for 1976, compared withfive to six per day at the time of the Staff's review ofUnit 1. At that time, the Staff concluded that about
2,400 operations per year represented no undue
risks to the health and safety of the public. The Unit
1 technical specifications require that the Applicantsmonitor and report to NRC the number and size ofcraft using the field. Only a substantial increase in
the usage rate would warrant the Staff's reconsideration of its position (supplemental testimony ofJ. B. J. Read, following Tr. 1297). The Board's
questions concerning the options that the Staff
might then exercise resulted in supplemental Staff
testimony to the effect that Department of Transportation information projects a 50% to 100%
i ncrease in airport operations during the period 1975
to 1990; conservatism in the crash probability analyses are consistent with the Staff's judgement thata significant increase in the frequency of operations
is needed to justify a reevaluation of the risk to the
public of larger than design basis aircraft; corrective
measures such as restrictions of airspace in the site
vicinity or hardening of plant structures could potentially be undertaken; alternatively, plant shutdown
may be required if the crash probability becomesunacceptably large.
50. We find that proper account has been takenof the current and anticipated airport traffic. Indeed,
we find that there will be an adequate opportunity toanticipate an increase in heavy aircraft traffic well inadvance of any increase potentially posing an unac293

program is not intended for use in formulating nor ini mplementing evacuation plans. With respect to theability of active, real-time detectors to aid in evacuation plans, such detectors would again be of little
or no value. Instrumentation used to determine theseverity of an accident, and the need for any offsite
emergency action, is located on site and is monitored from the reactor control room. This instrumentation monitors area conditions and process
variables such as the reactor coolant temperatureand pressure and any abnormal release of radioactivity. In the event that accident conditions arose forwhich evacuation would be an effective protective
measure, necessary measurements and corrective
actions to mitigate the consequences, including
notification of offsite emergency personnel, would
be performed quickly, within 10-15 minutes of theincident. It would, therefore, be unlikely that any
offsite active detectors would register any abnormal
reading since no release from the containment
would as yet have occurred. Only after someperiod of time (to allow the release and transport ofradiation emitters) would the detectors be of any
use, and even then they would add nothing to theinformation that the previously dispatched offsite
survey teams would not already have gathered.
54. In summary of this matter, the Board findsthat the radiological effluent and environmental monitoring programs as proposed by the Applicants andapproved by the Staff are adequate to measure andevaluate normal radioactive effluent releases and tomeasure radioactivity in the plant environs; and that
active, real-time detectors would add nothing to thepresent capability. We further find that the
response or effectiveness of both in-plant instrumentation and offsite personnel in the event of an
accident would not be aided or improved by suchdetectors (testimony of Porter, following Tr. 1011;
testimony of Osloond and Stoddart, following Tr.
1060; testimony of Van Niel, following Tr. 1060; testi mony of Wayne Britz).

ceptable risk. We find that such an increase isunlikely and that should it nevertheless occur,
acceptable corrective measures can be taken to
make the risks acceptable.

Contention 6
The environmental radioactivity monitoring program of the Applicants is inadequate to accurately
measure the dose delivered to the public during
normal and accident conditions. Only active, realti me detectors can determine what the actual dose
rate is. Furthermore, an array of offsite detectors
could greatly aid in possible evacuation plans. No
operating license should be granted until the Applicants provide a network of active radiation monitors.
51. The Board views this Contention as comprisi ng two allegations:(a) The actual radiation dose received by the publicduring normal and accident conditions can be properly measured only if offsite, real-time detectors are
deployed.
(b) The implementation of evacuation plans could
be greatly aided by the deployment of such detectors.
52. Based upon a review of Applicants' present
capabilities to monitor and assess radioactive
releases from TMI-2, as well as upon the advantages and disadvantages of employing active realti me detectors, the Applicants and the NRC Staff
are in agreement that the current monitoring capabilities of Applicants are adequate. They also agree
that installation of the type of real-time detectors
currently commercially available would provide no
meaningful improvement over the existing system;
indeed, certain disadvantages were noted. For normal releases, the Applicants sample and analyze therelease at its source prior to discharge, monitor the
release at the time of discharge, and variously takecontinuous composite samples and grab samples of
releases. Through a wide variety of types of samples, of types of detectors, and of locations, includi ng thermoluminescent dosimeters, sampling of surface water, drinking water and rain water, collectionof particulates and iodines, and collection andanalysis of vegetation, soil, and agricultural products
i n the TMI site environs, radiation levels andradioactivity around the plant site are measured toassist the Applicants in assessing the impact of
releases, and to provide confirmation of the effluent
monitoring results done at the points of release.
53. With respect to off-normal conditions thatmight justify the evacuation of members of the publi c within the low population zone, testimony wasoffered to the effect that the environment monitoring

Contention 8

The warning and evacuation plans of the Applicants and the Commonwealth of Pennsylvania are
i nadequate and unworkable. The plans assume that
all local and state officials involved are on 24-hour
notice and can be contacted immediately. They
further assume that all people notified will promptly
react and know how to respond and are trained inwhat to do. They also assume that the public which
has been assured that accidents are "highly
unlikely" or "highly improbable," will respond andallow themselves to be evacuated. No operating294

Underlying all of those is the need for the existenceof dependable, prompt, and intelligible modes ofcommunication amongst the emergency plan participants and with the public. The referenced testi mony is replete with evidence confirming this.
Examination by the Intervenors and the Board castno doubt upon the adequacy of the communications
equipment and the various modes of communication. The Board finds these matters to be satisfactory.
62. We turn now to Item (a) above. In the eventof an accident, TMI-2 personnel initially contact theState Council of Civil Defense Duty Officer and the
Dauphin County Civil Defense Headquarters. Calls
also would be made by Applicants directly toPennsylvania State Police, Hershey Medical Center,and the Brookhaven Assistance Group, as necessary. The State's Civil Defense (CD) Duty Officer isavailable twenty-four hours a day, seven days aweek; the County Civil Defense Headquarters, which
serves as the constant communications center for
all emergencies in the county, is always manned.
Similarly, Pennsylvania's Bureau of Radiological
Health (BRH), which is the Commonwealth's expert
radiological advisor and whose personnel are notified immediately by the state civil defense duty officer, maintains a number of contact points where
BRH representatives can be reached by the CD
duty officer. Upon receipt of the call from the CD
duty officer, the BRH representative then contacts
TMI on one of its multiple phone lines to confirm thevalidity of the initial notice to CD and to receive
details of the event. In the event that BRH cannot
be contacted (considered remote in view of BRH's
multiple contact points and successful drills in thepast), civil defense could proceed based on Applicants' expert recommendations as to the need forprotective action.
63. The Dauphin County CD unit claims to have
responded effectively to several disasters over the
past several years involving evacuation of the public
and the handling of physical injuries. These claims
were not disputed. The Board finds that a randomly
required initiation of the appropriate emergency
response plans will not fail due to any inability tocontact state and local officials.
64. Regarding Item (b) as noted above, priorsuccessful disaster responses (albeit to nonradiological events) also support the conclusion thatstate and local officials are knowledgeable about
their jobs. Joint Intervenors and the Board wereparticularly interested in the effect on the emergency response plans if the state's lead radiologicalassessment agency, i.e., the Bureau of Radiological
Health, should suffer a reduced capability. Thisand evacuation plans are shown to be workablethrough live tests.
The Applicants'
prepared testimony
58.
described the plans and procedures which govern
their actions in accident situations; described theequipment relied upon both for accident detectionand evaluation and for assured communications withoffsite authorities; and described pertinent portionsof their training program, including emergency drills(testimony of J. G. Herbein, G. P. Miller, and R. W.
Dubiel, following Tr. 757; testimony of Thomas
Potter, following Tr. 1556). The Joint Intervenors
presented no prefiled testimony, but conducted
extensive cross-examination and submitted proposed findings on this contention. This was the
only contention for which the Commonwealthpresented prepared testimony and submitted proposed findings, adopting as its own the Applicants'
proposed findings numbered 43 through 56.
59. The Witnesses for the Commonwealth ofPennsylvania were from the state and local civil
defense organization. Their testimony described thecivil defense organizational structure; the actionplans that would be followed in the event of an
emergency, including a nuclear power incident; anddescribed their experience in evacuation involving
nonnuclear events (testimony of K. J. Molloy and C.
A. Williamson, following Tr. 801).
60. The Staff's testimony described the resultsof its review of the Applicants' emergency responseplans, including the ability to provide early warning
to the public, to arrange for public evacuation, andto interface appropriately with the state (testimonyof C. R. Van Niel, following Tr. 1701; testimony ofCharles Gallina and Phil Stohr).
61. We see no need to recite here-as do the
proposed findings of the Applicants, the Commonwealth, and the Staff-those uncontradicted,
descriptive characteristics of the Applicants' state of
preparedness, nor that of the cooperating state andlocal agencies upon whom the success of the emergency plans depend. We find these to be adequate.
We do address those assumptions deemed by theIntervenors to be necessary for the success of theemergency plans, and hence challenged by thiscontention, namely,(a) that appropriate state and local officials areavailable to be contacted any time they are needed;(b) that such personnel, upon being notified, willknow the right thing to do and will do it promptly
because they have been so trained; and(c) that any members of the public that should be
evacuated will respond appropriately and will permit
themselves to be evacuated despite there having
been no live drills or tests of the public response.
295

possibility was suggested by a press release fromthe Department of Environmental Resources, within
which BRH operates, indicating that the statebudget may reduce funds for radiological monitoring(Board Exhibit 1). NRC Staff witnesses, whenpresented with information in the press release,generally observed that the NRC requires an adequate emergency plan, and that should that plan
become insufficient for some reason, the Applicants
would be required to fill the gap (Tr. 1075-1090). In
fulfilling the Board's request to specifically address
the question of responsibilities (Tr. 1097-1099), theStaff determined that it would, in fact, have several
options available to it, including having the Applicants fill the void, looking to other groups within thestate, or perhaps filling the void at the Federal level(Tr. 1745-1749). Furthermore, the Staff's witness
observed that the Applicants' monitoring capability
outside the LPZ would be more than adequate until
such time as subsequent or supplemental monitori ng teams would be available to the Commonwealth.
I ndeed, the NRC regional office itself could provide
up to 20 additional inspectors, in addition to otherteams from Brookhaven Laboratory and radiologicalteams from western Pennsylvania (Tr. 1806-1809).
65. The testimony stresses the drills and trainingthat various emergency response groups undergo.
The Commonwealth's civil defense witnesses saw
no compromise of their own effectiveness of
response because of their not having technicalknowledge and training concerning radiologicalmatters.
Staff witnesses testified that theCommonwealth's BRH possessed the requisite
radiological know-how needed to assist with protection of the public health and safety. The Board
finds that the evidence adequately supports theconclusion that the effectiveness of state and local
officials is based upon an adequate knowledge of
their job. These officials will not be hampered by
not having had technical training in radiologicalmatters.
66. Finally, we address Item (c), regarding thenecessity of the public's being subjected to live
tests or drills in order to insure that it will respond
appropriately. All witnesses agreed that membersof the public need not be drilled to assure theirproper response to emergency evacuation instructions. Witnesses for the Commonwealth's CD

organization explicitly offered the opinion that such
drills might be counter-productive, citing a Stanford
Research Institute study to support this opinion, andpointed to the actual behavior of the public during
disasters in their own recent experience as being
satisfactory and supportive of the lack of need for
drills. The Staff similarly cited an EPA evacuation
study. Examination by the Intervenors elicited theinformation that conclusions regarding the lack ofneed for public drills were without the benefit ofexperience with radiological events requiring evacuation.
Nevertheless, the Board's examination
revealed that such diversity of nonradiologicalevents had been successfully dealt with to provide
confidence that drills are not necessary. Furthermore, the Board additionally determined that thecivil defense emergency preparedness literaturethat has been disseminated to the public is being
revised to include radiological awareness andresponse information. The ability of the County's
CD organization to adequately cope with the
management of public vehicular traffic during anevacuation was also examined by the Board (Tr.
1731-1735; Tr. 1840-1841; Tr. 2528-2541).
67. The Board thus finds that Item (c) states anassumption supported by a preponderance of theevidence. More broadly, we find that the record
supports the conclusion that Contention 8, in its
entirety, is without merit and that the Staff has properly assessed the adequacy and workability of theemergency response. We also find the emergency
and evacuation plans to be both adequate andworkable.
'On August 15, 1974, a petition to intervene was
filed by Gertrude and Frederick Hellrich, et al. Intervention was granted by the Board but thereafter, on
August 20, 1976, these intervenors withdrew fromthe proceeding.
At the evidentiary hearing in this matter, theApplicants and the Commission's Regulatory Staff
made their responses to a number of questions
asked by the Licensing Board. The matters raisedby the Board concerning the issues in controversy
among the parties, or the environmental review, arediscussed in this decision.
2296

Cite as 8 NRC 9 (1978)
UNITED STATES OF AMERICA
NUCLEAR REGULATORY COMMISSIONATOMIC SAFETY AND LICENSING APPEAL BOARD

Jerome E. Sharfman

Alan S. Rosenthal, Chairman
Dr. W. Reed Johnson
Docket No. 50-320

I n the Matter of
METROPOLITAN EDISONCOMPANY, et al.
(Three Mile Island Nuclear
Station, Unit No. 2)

July 19, 1978
DECISION

Unit No. 2 of the Three Mile Island Nuclear Station (TMI-2), located adjacent to a similar unit on ani sland in the Susquehanna River about 12 miles from
Harrisburg, Pennsylvania, received a construction
permit in November 1969, prior to enactment of the
National Environmental Policy Act (NEPA). Therefore, no environmental review was performed inconnection with the application for that permit.
Subsequently, after the applicants (Metropolitan Edison Company, et al.) had sought an operating
li cense, a Licensing Board undertook to consider
both (1) those environmental and safety questions
bearing upon the issuance of such a license; and (2)whether, as a result of a complete environmental
review, the previously issued construction permit
should be continued, modified, terminated, or
appropriately
conditioned to protect environmental
1
valuesOn December 19, 1977, the Licensing Board
issued an initial decision in which it concluded thatthe construction permit should remain in effect andauthorized the Director of Nuclear Reactor Regulation to make findings requisite to issuance of a fullterm operating license (subject to specified environmental conditions). 2 Exceptions to that decisionwere filed by Citizens for a Safe Environment andthe York Committee for a Safe Environment, joint
intervenors below. 3 Those intervenors also moved
us to stay the effectiveness of the initial decision. In
ALAB-456, 7 NRC 63 (January 27, 1978), we
denied the motion.
The intervenors renewed their stay request

before the Commission. They stressed, as they
had before us, 5 their disagreement with the Licensi ng Board's rejection of their claim that the environmental review of the nuclear fuel cycle had notcorrectly dealt with the effects of radon (Rn-222)
releases generated by mill tailings produced in thecourse of the mining and milling of uranium. In
ALAB-456, we had held that this claim was "barred
as a matter of law for the reason that it constitutes
an impermissible attack upon a generic regulation of
the Commission"-Table S-3 of 10 CFR 51.20(c). 6
The Commission, however, as was within its (but notour) authority, agreed with the intervenors that theradon release values in Table S-3 were incorrect
and accordingly set aside that portion of the table.
CLI-78-3, 7 NRC 307 (March 2, 1978). Although it
denied the requested stay, the Commission directed
us to review the issue "as though no Rn-222
release figure had been determined by regulation iii
Table S-3." Id. at 310. With that in mind, and foll owing discussion of the matter with the parties atoral argument, we remanded the radon issue to the
Licensing Board for further consideration. ALAB465, 7 NRC 377 (March 27, 1978). But subsequently, in an order encompassing all the cases
before us involving the radon matter, we determinedthat one particular proceeding pending before alicensing board should be treated as the "leadcase," with supplementary material to be received inother cases (including this one) where appropriate.
Philadelphia Electric Company (Peach Bottom
Atomic Power Station, Units 2 and 3), et al., ALAB4297

480, 7 NRC 796 (May 30, 1978). As a result, wevacated the remand in ALAB-465. The radon issue
remains before us pending the pursuit of the procedures outlined in ALAB-480. 8
Now ripe for disposition are the remaining issues
raised by the intervenors on appeal. Only two are
sufficiently substantial to warrant discussion: theadequacy of the applicants' emergency plan and theprobability of a crash of a heavy aircraft into theplant. With respect to the former question, thei ntervenors have moved to reopen the evidentiary
record. We have reviewed their claims and havefound insufficient cause either to reopen the recordon the emergency plan or to disturb the result
reached by the Licensing Board on that question.
As for aircraft crashes, our review has led to a different result. The record does enable us to findreasonable assurance of safety given present levelsof aircraft traffic in the vicinity of the plant. But it
contains sufficient inconsistencies and ambiguities
relative to aircraft crash probabilities over the life of
the plant that we must order a further hearing onthat question. There is, however, no need tosuspend the operating license pending the outcomeof that hearing. 9

I. EMERGENCY PLANNING
fire departments, and the NRC Brookhaven Assistance Group (id., pp. 3-4, 10). The record includes
agreements between the applicants and various
outside organizations spelling out the responsibilities
the organizations would assume.
Stated in an extremely simplified way, thesequence of activities following an accident orincident, or other cause of radioactive release,would be as follows. The occurrence of the event
would be detected, and its severity assessed, bymeans of instruments located onsite and monitored
in the control room (and confirmed and augmented
by portable equipment)(see Herbein, et al., p. 5;
also, LBP-77-70, 6 NRC at 1201-02). Thereupon,
the applicants would notify first the State Council of
Civil Defense duty officer (who is available at all
times) and then (as necessary) the State Police, anearby medical center, and NRC (Herbein, et al., p.
10; Tr. 792). In the event of the most serious typeof incident, the occurrence would become known inseconds, and the duty officer would be notified
within 5 minutes (Tr. 1606). That officer in turnwould notify the county civil defense organization(ibid.), which is also manned without interruption(Molloy, prepared testimony, fol. Tr. 801, p. 3), andthe BRH duty officer. BRH would confirm the notification by recontacting the applicants (Tr. 1611, 1745,
1827A).
The information provided by the applicants to theState and local organizations would vary depending
upon the nature of the event in question (Tr.
767-68); in all instances, however, it would include
such data as might be available to assist in determining whether (and in what area) evacuation was
called for. The applicants would also make a
recommendation as to evacuation (Tr. 1606-07), but
the State would make the final determination, based
upon the advice of BRH (Herbein, et al., pp. 3-4; Tr.

A. The Final Safety Analysis Report (FSAR) for
every operating license application must include"[p]lans for coping with emergencies." 10 CFR
50.34(b)(6)(v). While it need not include the "detailsof these plans and the details of their implementation," the FSAR must at least describe certain
defined elements "to an extent sufficient to demonstrate that the plans provide reasonable assurance
that appropriate measures can and will be taken in
the event of an emergency to protect public healthand safety and prevent damage to property." 10
CFR Part 50, Appendix E, Part III (emphasis supplied).10
The emergency plan for this reactor appears in
Section 13.3 of the FSAR, as supplemented by
Appendix 13A. Additional descriptive material relati ng to the plan was presented by a panel of theapplicants' witnesses (Herbein, et al., prepared testi mony, fol. Tr. 757) and by two witnesses sponsored by the Commonwealth of Pennsylvania (fol.
Tr. 801). The staff both reviewed the plan in its
Safety Evaluation Report (SER, Section 13.3) andpresented testimony on it (Van Niel, prepared testi mony, fol. Tr. 1701).
I n general, the plan anticipates that "the station
will be self-sufficient in handling emergency conditions" but that "outside agencies will be called uponas needed" (FSAR, Section 13.3.1). The applicants
are to be responsible for initially detecting theoccurrence of an accident or event giving rise to an
emergency situation; taking corrective action (where
possible); assessing potential offsite and onsite
effects, and timely notifying local, State, and Federal
authorities (Herbein, et al., pp. 1, 4). Among theauthorities that might assist in responding to an
emergency are the State and local (Dauphin County)
civil defense organizations, the Pennsylvania Bureauof Radiological Health (BRH), the State Police, local298

1363-64, 1481-82, 1625, 1654-57). The Dauphin
County Civil Defense organization, acting throughl ocal fire and police departments and local civil
defense personnel, would carry out the evacuation.
The Environmental Protection Agency has
promulgated guidelines which would call for protective action to avoid doses to individuals in excess of
5 rem whole body of 25 rem to the thyroid." Theapplicants' evidence indicated that, assuming theoccurrence of the maximum hypothetical accident
postulated under 10 CFR Part 100, nondispersive
atmospheric conditions, and the transport ofradioactive material in the direction of the greatest
number of people near the site (i.e., north, toward
Middletown, Pennsylvania), those dose levels would
not be exceeded (1) within 45 minutes of the time ofthe event at a distance of 1 mile from the site; (2)within 3 hours at a distance of 2 miles from the site
(on the fringe of the more densely populated areasof Middletown); (3) within 5 hours in the center ofMiddletown; and (4) at any time beyond 4.8 miles
from the site (Herbein, et al., pp. 8, 9). The Directorof the Dauphin County civil defense organization( Kevin J. Molloy) testified that, in these circumstances, no more than 15,000-18,000 persons
would have to be evacuated (Molloy, supra, p. 7; Tr.
1409,1447-48,1452). He concluded that "we could
effect and complete an evacuation of this typewithin the period allotted us"-i.e., less than 1 hourfor persons located closest to the island, less than 3
hours for those on the edge of the more densely
populated areas of Middletown, less than 5 hours
for those in the center of Middletown, and "a couple
more hours" out to 5 miles (Molloy, pp. 10, 6; Tr.
1411). The staff determined that the organization andprocedures proposed were adequate and that theapplicants' plan satisfied applicable requirements(Van Niel, pp. 4-5). The Licensing Board agreed,finding the emergency and evacuation plans to be"both adequate and workable." 6 NRC at 1206.
B. With this background in mind, we turn to theparticular criticisms leveled against the emergency
plan by the intervenors. Both before the Licensing
Board and on appeal, the intervenors have asserted
that the plan is "inadequate and unworkable" forseveral discrete reasons-virThe plans were based upon the unproven andquestionable assumptions that all necessary officials will be available at all times, will know how to
respond and will react promptly, and that membersof the public will respond to a radiological emergency and allow themselves to be evacuated....
Brief on appeal, p. 8. They additionally haveadvanced two legal claims: that the Board improp299

erly limited the scope of their cross-examination,and that the plan is inconsistent with thePrice-Anderson Act. We will treat these mattersseriatim.
1. Central to the intevenors' challenge to theadequacy of the evacuation plan is their expressed
belief that "live tests and drills" are essential. They
reason that radiological emergencies are different
from other emergencies and that the effectivenessof the plan can be ascertained only through tests
i nvolving the potential evacuees.
The evidence, however, is to the contrary.
Witnesses for the Commonwealth expressly
discounted the need for or desirability of live drills.
The Director of Civil Defense for Dauphin County
questioned whether such drills would be meaningful
and whether most people would participate; indeed,
he suggested that they might prove counterproducfive inasmuch as a real emergency was not likely toconform to a test situation and an appropriate
response to one might not be an appropriate
response to the other (Molloy, p. 13; Tr. 1463). On
the basis of a Stanford Research Institute study,
substantiated by his personal knowledge of two
events in Pennsylvania, the Deputy Director of theState Council on Civil Defense expressed a similarview (Williamson, prepared testimony, fol. Tr. 801, p.
10). He specifically pointed to (1) a planned extensive public evacuation exercise in Erie, Pennsylvania, in which actual public participation had been"minimal" and (2) the successful evacuation withinapproximately 4 hours of more than 100,000 people
from Wilkes-Barre in the wake of Hurricane Agnes(ibid.). To the same effect, see also Tr. 1463,
1468-69 (Molloy); Tr. 1642-43 (applicants' witness);
Tr. 1829-32, 1938-42 (staff witness); but cf. Tr.
1835 (recognizing "some diversity of opinion" in thisarea). Accordingly, the Licensing Board's rejectionof the intervenors' thesis regarding live drills (6 NRC
at 1206) is well-founded in the record. 12
Closely tied to the intervenors' claim regarding
the need for live drills is their assertion below that a
predicate to a successful emergency plan isknowledge on the part of those who would be evacuated of the nature and consequences of radiological events. 13 As in the case of live drills, however,
the record firmly establishes that such knowledge is
not necessary. Indeed, a staff witness who hadparticipated in the review of the emergency plan
testified, on the basis of his more than 5 years'
experience in emergency planning, that "the general
population reacts more readily, fears more readily
things which it knows nothing about" (Tr. 1852); andthat, when confronted with such an event, a person"generally responds to people who tell him what todo to protect his health.... It is the fear of the unknown that makes [people] act" (ibid.).
2. Although discounting the need for live drills
involving the public, the witnesses for the Commonwealth, the applicants, and the staff all acknowledged the desirability of drills for personnel
assigned responsibilities under the emergency
plan 14 The plan provides for such drills by applicants' personnel and others charged with responsibilities under the plan. See FSAR, App. 13A, Section
13A.10; Herbein, et al., pp. 11-12; Molloy, p. 12, andTr. 1457; Williamson, pp. 9-10; Van Niel, p. 4 and Tr.
1829-30
The intervenors' only challenge to these provisions (aside from the failure to involve the generalpublic, as discussed above) appears to rest on theirassumption that the drills are announced in advanceand hence are not "random." This assumption is
not justified. It is founded wholly on the acknowledgement by an applicants' witness that somedrills are scheduled and the participants so advised(Tr. 786-88, 793). But the same witness indicatedthat such notice is given for only one-third to onehalf of the drills (Tr. 793)(see also Tr. 1079).
It bears noting that the provision for drills for Unit
2 parallels the requirement in effect under the emergency plan for Unit 1 (Tr. 1655). A staff witness testified, without contradiction, that he had observed
two full-scale drills at Unit 1 and "in my opinion the
drills [were] probably some of the best drills that I
have seen conducted, wider in scope than I haveseen in other areas, and the emergency planning as
a whole has proven to me, or has been shown tome as being much more than adequate" (Tr. 1856).
3. The intervenors challenge the adequacy of the
training program for persons who will carry out anemergency plan. 15 Specifically, they claim that theplan can be effective only if those persons haveexpert knowledge of the effects of radioactivity. But
they point to no evidentiary foundation for that proposition.16 I ndeed, all the testimony on this subject
contradicts the intervenors' conclusion. Mr. Molloy
emphasized that he is able to fulfill his evacuation
specialized
responsibilities effectively without
knowledge of radiation. He maintained that his evacuation personnel are adequately trained to carryout their responsibilities and, additionally, haveexpert assistance available to assist themprimarily from BRH and the applicants (Molloy, p. 5).
Further, one of his staff members is a radiologicaldefense officer (Tr. 1356-58,1361) and several hundred persons in Dauphin County have been trained
i n radiological monitoring and are available to assist
i n an emergency, in most instances as volunteer
firefighters (Tr. 1359-60). Approximately 50 percentof those who might aid in an evacuation have either

taken Pennsylvania's radiological monitoring course(as Mr. Molloy did)17 or had other radiological traini ng (Tr. 1449-50).
Even more important, Mr. Molloy insisted thatthose responsible for an evacuation would not need"detailed knowledge" of the event compelling that
action (Molloy, p. 6). Rather, useful knowledge
would be strictly limited and of a different genre:

What we need to know is generally the nature of
the problem, secondly what segment of the public
will be or could be affected, and what action on ourpart is recommended. With this information, ourorganizational structure and communications capabilities allow us to respond very quickly, callingupon and coordinating whatever groups or agencies the situation dictates.

Ibid.; see also Tr. 1363. To the same effect, see Tr.

Mr.
Molloy1686-87(applicants'
witness).
expressed confidence that his organization had (orwould have available to it) adequate knowledge ofthis sort (Molloy, pp. 5-6, 10-11; Tr. 1370-73,172224).
On this score, the staff testimony went evenfurther. It pointed to an Environmental Protection
Agency study (EPA-520/6-74-002, June 1974)
analyzing some 500 events-including floods, fires,
hurricanes, explosions, and release of toxic
substances-that had prompted evacuation. The
study had found no statistically significant difference
i n the effectiveness of evacuation with an emergency plan and without such a plan. A staff witness
opined that the study was relevant "because it talks
about the movement of people. The reason for the
movement, I think, is of secondary importance" (Tr.
1828). He added that the staff nonetheless believes
it prudent that there be "proper training and planningon the part of the officials responsible for evacuation" (Tr. 1833). Another staff witness attributed theemergency plan requirement to the Commission's
concept of "defense in depth" (Tr. 1834).
Finally, Mr. Molloy pointed to the wide variety ofemergency situations in which his organization had
successfully carried out evacuations (Molloy, p. 11).
He specifically mentioned floods, a plane crash, apassenger bus accident, a train derailment (ibid.),and natural gas seepage (Tr. 1361-62). And heunequivocally stated that his actions did not dependon detailed knowledge of these matters (Tr. 1362).
Given this evidentiary record, the Licensing
Board's conclusion that the effectiveness of Stateand local officials will not be hampered by a lack oftechnical training in radiological matters (6 NRC at1206) is manifestly correct.
4. The intervenors' remaining factual challenge
to the Licensing Board's evacuation determination issomewhat vague and diffuse; we understand it,
300however, to question the "availability at all times" of"officials" charged with evacuation responsibilities.
Although their brief on appeal does not specifically
identify the "officials" intervenors have in mind, it
seems probable that the intended reference waseither to State (or local) civil defense or to radiological health personnel.
a. No evidence of record casts doubt upon thetestimony that the State civil defense duty officer isavailable continuously and that Dauphin County civil
defense headquarters is likewise always staffed( Herbein, et al., p. 10; Molloy, p. 3; Van Niel, p. 2).
Moreover, in every test of the communications system, whether announced or random, the State or
county official sought to be reached was available(Tr. 792-94).
b. Insofar as BRH personnel are concerned, we
have seen that those individuals serve as radiological advisers to State and local civil defense personnel and, under the evacuation plan, would advise as
to the appropriateness of evacuation in a given
situation (see pp. 15, 18, supra). BRH also engages
i n offsite monitoring following an accident (Tr.
1075-76, 1668-69). Further, both Mr. Herbein (theapplicants' witness) (Tr. 1607, 1625) and Mr. Molloy(Tr. 1363-64) indicated that the receipt of advice
from a knowledgeable source (such as BRH) was
perhaps the most significant element in determining
whether evacuation should occur (as well as thearea involved).
At the hearing below, the intervenors questioned
whether budgetary curtailments would make BRH
unavailable for or incapable of performing its
assigned functions. Their inquiry was founded on a
public announcement of the Pennsylvania Department of Environmental Resources (BRH's parent
organization), dated May.13, 1977, to the effect thata budget cut for the 1977-78 fiscal year approvedby the Pennsylvania Senate would result in a drastic
curtailment of that department's services, including,inter alia, a reduction in the "radiologic healthenvironmental monitoring program and emergency
response capability" (Bd. Exh. 1, Tr. 1081-82).
But the record contains more than enough to
support the conclusion that others could fulfill BRH's
responsibilities under the emergency plan. The
applicants indicated that, if necessary, they would
notify NRC and make specific recommendations toachieve a substitution for BRH's capabilities (Tr.
1570-71). And there are clear indications that Stateand local civil defense officials are willing to rely
upon advice provided by the applicants or NRC,
either in conjunction with that of BRH or independent of it (Tr. 1363-64, 1368, 1499-1500, 1541,
1720-21, 2467, 2529-32). Beyond that, the staff
stated that it would require resort to one or more of301

a number of available means to fill the "void in theoverall emergency preparedness" created by any
inability of BRH to provide expected services (Tr.
1780-82; 1748-49). 18 Still further, the staff pointed
out that-it will keep track of the Commonwealth's
continuing ability to fulfill its assigned responsibilities(Tr. 1078-79, 1087, 1746). Notwithstanding thei ntervenors' claim to the contrary, the record amply
supports the conclusion that others could take overthe functions assigned BRH in the emergency plan
without the public safety being compromised.
c. In their appellate brief, the intervenors
attempted to augment their position on BRH's
potential lack of capability by referring to a statement made by the BRH Director at an EPA
workshop (November 30-December 1, 1976). The
statement analyzed the BRH experience in monitori ng radioactive fallout from Chinese nuclear tests
conducted in October 1976; and although indicatingthat BRH generally reacted satisfactorily todemands made upon it in the "fallout crisis,"expressed serious doubt that it "would have beenable to have responded as well" had there been anuclear reactor accident.
That statement appeared in a draft EPA reportwhich was not in the record before the Licensing
Board. At oral argument, therefore, we advised thei ntervenors' representative that we could consider it
only if he moved to reopen the record to include it.
Somewhat belatedly, he did so. 19 In ALAB-474, 7
NRC 746, 748 (May 5, 1978), we decided to holdthe motion in abeyance pending our review of therecord on emergency planning and then to determine it on the merits (despite its tardiness) because
it addressed an important safety question.
We recently have had occasion to reiterate thestandards for reopening a record. Kansas Gas &Electric Company (Wolf Creek Generating Station,
Unit No. 1), ALAB-462, 7 NRC 320, 339 (March 7,1978). As we there stressed, the proponent of amotion to reopen bears a heavy burden. The
motion normally must be timely presented andaddressed to a significant issue. Moreover, if an initial decision has already been rendered on thei ssue, it must appear that reopening the proceedingmight alter the result in some material respect. In
the case of a motion which is untimely without goodcause, the movant has an even greater burden; hemust demonstrate not merely that the issue is significant but, as well, that the matter is of such gravity
that the public interest demands its further exploration. See Vermont Yankee Nuclear Power Corp.
(Vermont Yankee Nuclear Power Station), ALAB138, 6 AEC 520, 523 (1973); id., ALAB-167, 6 AEC
1151-52 (1973). These criteria govern each issue tobe reopened; the fortuitous circumstance that aation of the areas in the immediate vicinity of TMI-2
is compounded because the record had alreadyshown that a Class 9 accident at TMI-2 could occur
by the crashing of a large aircraft into the TMI-2
plant." The likelihood of such a crash is discussed
in Part II of this opinion and in Mr. Sharfman's
dissent. It suffices for our purposes here to recall
that the requirements for evacuation planning arerooted in 10 CFR Part 100, 22 and that Part 100
assumes releases of radiation based upon ahypothetical major accident "that would result in
potential hazards not exceeded by those from any
accident considered credible." 23 Thus, what
accidents might conceivably occur at the particularplant in question is irrelevant to planning for emergency evacuation; that is based solely on the Part
100 hypothetical accident and the assumed releasesof radioactivity resulting therefrom.
6. I ntervenors' claim that the emergency plan24
somehow runs afoul of the Price-Anderson Act
25
It appears to rest on the
merits little discussion.
thesis that the applicants will be the sole source ofradiological information in the event of an accident;
that, as a result of Section 190 of the Atomic Energy
Act, as amended, 42 U.S.C. 2240, such information"cannot be used as evidence against the applicant
i n court"; and, hence, that the vesting of emergency
plan responsibilities in the applicants (particularly
those related to monitoring) "denies victims of a
nuclear accident the opportunity to introduce incourt the only evidence likely to establish a claim
under the Price-Anderson Act." This line of reasoni ng is, however, defective in several respects.
I n the first place, intervenors' factual premise thatapplicants are the sole source of radiological information is plainly incorrect. Postaccident monitoringis the responsibility not only of the applicants but
also of State agencies (primarily BRH), the Department of Energy, the NRC, and others (Tr. 1093-94,
1578-81, 1613-14, 1668-70, 1678, 1742-43, 1767,
1805-06). Even if BRH should be unable to fulfill its
monitoring responsibilities, other agencies (bothFederal and State) would take up the slack. See p.
20-21, supra.
More important, the intervenors' legal premise is
far wide of the mark. Section 190 of the Atomic
Energy Act provides thatproceeding has been or will be reopened on otherissues has no significance. See Georgia Power
Company (Alvin W. Vogtle Nuclear Plant, Units 1 and2), ALAB-291,.2 NRC 404, 413-14 (1975).
Plainly, intervenors' motion does not satisfy theabove criteria for reopening. 20 Review of the statement and analysis of the issue demonstrate that the
BRH Director raised only one matter relevant here:
whether the bureau could fulfill its responsibilities for
postaccident monitoring under the emergency plan.
The statement does appear to question BRH's
existing ability to conduct widespread environmental
sampling and long-term laboratory analyses of such
samples-activities incident to, but not directly
involved with, emergency evacuation procedures.
As we have seen, however, the question of BRH
capability to respond to an emergency has alreadybeen fully litigated, in the context of the budgetary
constraints which BRH might face. And we havealso determined on this record that BRH participation is not essential to a successful emergency evacuation, since the applicants and NRC could fulfill
the responsibilities assigned under the plan to BRH.
That being so, reopening the record could notchange the result previously reached and hence is
not warranted . 21
5. The intervenors claim that the Licensing
Board improperly limited their cross-examination
with respect to the size of the area to be considered for evacuation in the emergency plan. Theyi nsist that they should have been allowed to explore
the feasibility of evacuation of areas beyond 5 miles
from the reactor.
Intervenors' position is directly contrary to New
England Power Company ( NEP, Units 1 and 2), et al.,
ALAB-390, 5 NRC 733 (1977). We there determined that existing Commission regulations do not
require consideration in a licensing proceeding of"the feasibility of devising an emergency plan for theprotection (in the event of an accident) of persons
located outside of the low population zone." 5 NRC
at 747. The LPZ for this facility extends 2 miles out
from the reactor (SER, Section 2.1.3). It is true that,for reasons which need not be discussed here, theapplicants and the staff nevertheless looked into thepossible need for protective measures within a 5mile radius of the reactor-and the intervenors werepermitted to cross-examine on the evidence
presented in this regard. It scarcely follows fromthis fact, however, that the question of emergency
planning at still greater distances from the LPZ
boundary had to be explored at the intervenors'
i nstance.
Intevnenors further argue: "The prejudice to the
public interest by this restriction of inquiry to evacu-

No report by any licensee of any incident arisingout of or in connection with a licensed activity
made pursuant to any requirement of the Commission shall be admitted as evidence in any suit or
action for damages growing out of any matter mentioned in such report.

The "action for damages" which intervenors have inmind is one arising under the provisions of302

Price-Anderson (i.e., Section 170 of the Act (see fn.
24, supra.)) Under those provisions, the licensees
waive, inter alia, "any issue or defense as to conduct of the claimant or fault of persons indemnified"(Section 170n. (I)(c)(i), 42, U.S.C. 2210 (n)(I)(c)(i); 10
CFR 140.2(c)). With limited exceptions not relevant
here, a claimant would have to prove only causationand the severity of any injury in order to recoverdamages. The availability of the licensees' monitori ng reports would be of little consequence because
the Commission itself is required to make a public
report on the incident (presumably to be based insupplied
by
the
part
on
i nformation
licensees)(Section 170i, 42, U.S.C. 2210(i)).

Further, the use limitations in Section 190 are
strictly limited to particular reports submitted to theCommission and (as the applicants concede) would
restrict neither (1) an individual's rights informally torequest or formally to discover information and data
possessed by the applicants (as licensees) concerning the offsite consequences of an accident;nor (2) his use of that information and data. In otherwords, while the use of the report itself may be circumscribed by Section 190, the use of the information and data undergirding the report is not.

II. AIRPLANE CRASHES

4On February 27, 1978, they also sought a judicial stay of the operating license authorization, but
the court of appeals denied their request. Kepford
v. NRC, No. 78-1160 (D.C. Cir., March 8,1978).

As a result of the facility's relative proximity to
Harrisburg International Airport (formerly Olmstead
Air Force Base), a significant issue throughout thisli censing proceeding (as well as that for Unit 1) has
been whether the public is adequately protectedagainst the hazards of a crash of an airplane into
the facility. The reactor's vital structures, power
supplies, and cooling water sources ("safety structures") have been designed to withstand the aircrafti mpact and fire effects from the crash of a200,000-pound plane traveling at 200 knots, the"design basis crash." 26 The crash of an airplaneheavier than 200,000 pounds into TMI-2 has been
calculated by the applicants and staff to have sucha low probability that it does not present a hazard to
the public, and therefore the plant need not bedesigned to withstand its effects. Because the probability of an airplane crash is proportional to thelevel of aircraft traffic, the determination that thecrash probability for heavy aircraft is acceptably low
reflected both the current level of heavy aircraft
traffic at the airport and the projected magnitude ofsuch traffic in the future.
The Licensing Board accepted this analysis (6NRC at 1197-1200), despite the intervenors' challenges to the crash probability assessments of theapplicants and the staff. The intervenors appeal
from the Board's determination.

The issue was before us both through the intervenors' exceptions and as part of the stay request.
67 NRC at 65. The Licensing Board had applied
the Table S-3 values; the intervenors' position wasthat those values were erroneous. But that Board
also admitted into evidence (and permitted crossexamination on) testimony proffered by the intervenors (and responsive testimony offered by thestaff) on the health effects of radon releases and theeffect of such releases on the comparative
nuclear-coal cost-benefit balances. Without determining whether such testimony constituted ani mpermissible challenge to Table S-3, and granting
arguendo the correctness of the intervenors'
analysis, the Board determined the radon impact "tobe of negligible materiality" and insufficient to alter
the comparison between the nuclear and coal alternatives 6 NRC at 1224.
7
Duke Power Company (Perkins Nuclear Station,
Units 1, 2, and 3), Docket Nos. STN 50-488, STN
50-489, STN 50-490.
80n July 14, 1978, the Perkins Licensing Board
rendered its partial initial decision on the radon
matter. LBP-78-25, 8 NRC 87.
9This Board's sua sponte review of the remainderof the record has disclosed no other error warranti ng corrective action.
Insofar as intervenors' request for financial assistance is concerned, the Commission has held thatno such assistance is to be granted in a proceedingof this type. Nuclear Regulatory Commission(Financial Assistance to Participants in Commission
Proceedings), CLI-76-23, 4 NRC 494 (1976). We
5'See 10 CFR Part 50, Appendix D, Section C(1974 ed.).
2 LBP-77-70, 6 NRC 1185. An operating license( DPR-73) was issued on February 8, 1978. See 43
Fed. Reg. 7073 (February 17,1978).
3
An appeal was also filed by a nonparty; we
dismissed it for that reason. ALAB-454, 7 NRC 39(January 23, 1978).
303

and the licensing boards are, of course, bound bythat ruling. Detroit Edison Company (Greenwood
Energy Center, Units 2 and 3), ALAB-376, 5 NRC
426, 428 (1977).

another State agency, development of an"interagency cadre" to handle the BRH functions, or
possible assumption of responsibility by the Federal
Government (ibid.) Cf. Williamson, p. 5.
19
At our request, the applicants, by letter dated
March 24, 1978, supplied us with a copy of the draft
report.
20'There is some question whether the intervenors' failure to raise the issue suggested to themby the December 1976 statement earlier than January 1978, when they filed the brief which first mentioned it, should preclude them from raising it now.
The draft report is undated and it is unclear precisely when it was issued. An affidavit of the BRH
Director states that he received it "early in 1977"(Gerusky, affidavit dated April 26, 1978, par. 3).
Intervenors claim they were not aware of it until
January 1978. But that, even if true, does not settle
the matter.
Pennsylvania was participating in this proceedingas an "interested State" (see 10 CFR 2.715(c)). Duri ng the hearing below in April 1977, intervenors
requested that a BRH witness appear and testify as
to that organization's capabilities (Tr. 888). Afterthe Commonwealth interposed an objection to thatrequest, the intervenors withdrew it (Tr. 891). Even
if the intervenors were not aware at that time of the
December 1, 1976, statement of the BRH Director,
had they persisted in their attempt to examine a
BRH witness on BRH's capabilities and had theirrequest to do so been granted, any present or projected weaknesses in those capabilities could havebeen brought to light by thorough questioning.
21There appears to be no evidentiary support
whatsoever for other assertions made by the intervenors in their motion to reopen, to the effect thatthe Director of BRH had suggested in an otherwise
unidentified public statement that he and membersof his staff would not be on 24-hour call to respondto an emergency, and that the Director had stated inanother unidentified statement that BRH had suffered a manpower loss "since the date of the EPA
document." The Director by affidavit has explicitly
denied making any such statements and has confirmed that BRH is in fact on 24-hour call. Gerusky,
affidavit dated April 26, 1978, pars. 4, 5.
22
NEP, supra.
23
Footnote 1 to 10 CFR 100.11(a).
24The provisions of the Price-Anderson Act arecontained in Section 170 of the Atomic Energy Act,as amended, 42 U.S.C. 2210. Their constitutionality
recently was upheld by the Supreme Court. Duke

10

The elements of an emergency plan which are
identified in the regulations pertain to, inter alia, theorganizational structure relied upon for coping withemergencies; communications systems to be used
to keep various involved organizations informed ofmatters bearing upon their responsibilities, themeans for determining the magnitude of radioactive
releases; identification of first aid, decontamination,and treatment facilities; training of and drills for persons charged with emergency planning responsibilities; and criteria for determining the appropriatenessof reentry into the facility and resumption of operations. 10 CFR Part 50, Appendix E, Part IV.
11
Herbein, et al., p. 9.
12We note that about a year ago the Commission
denied a rulemaking request which sought a general
requirement for licensees to conduct an "actual evacuation drill" as a precondition for obtaining ali cense 42 Fed. Reg. 36326 (July 14, 1977).
13
The assertion does not appear to have been
directly advanced on the intervenors' appeal.
14
An emergency plan must include, inter alia,"[p]rovisions for testing, by periodic drills, of radiation emergency plans to assure that employees ofthe licensee are familiar with their specific duties,
and provisions for participation in the drills by otherpersons whose assistance may be needed in theevent of a radiation emergency." 10 CFR Part 50,
Appendix E, Part IV.1. Significantly, the appendix
l acks any requirement or suggestion that live drills
i nvolving the public be included in an emergency
plan.
15

An emergency plan must include "[p]rovisions
for training of employees of the licensee who areassigned specific authority and responsibility in theevent of an emergency and of other persons whose
assistance may be needed in the event of a radiation emergency." 10 CFR Part 50, Appendix E, Part
IV.H.
16

1 n support of the proposition, they rely solely
upon Mr. Molloy's admissions that his only special
knowledge of radiation (or of the consequences ofradiation) is derived from a week-long seminar on
emergency planning for nuclear facilities (Tr.
1355-56, 813-14, 837; see also Tr. 1567). Plainly,that evidence provides no basis whatsoever for the
point intervenors are attempting to make.
17
See n. 16, supra.

Power Company v. Carolina Environmental Study
Group,, U.S.
, 46

18

These means include the expansion of theapplicants' capabilities, replacement of BRH by

U.S.L.W. 4845 (June 26, 1978).

304

apparently overlooked the intervenors' unsuccessfulattempt to include the Price-Anderson matter intheir cross-examination on evacuation (Tr. 1782-83,
2505-12) and their filing of a proposed "finding"(par. 65) and "conclusion" (par. 94) on the subject(Intervenors' Proposed Findings of Fact and Conclusions of Law, dated August 15, 1977).

25

The applicants correctly point out that thePrice-Anderson question was not explicitly encompassed by the intervenors' contentions. The staff
goes on to assert that the question also "was notraised otherwise below" and asks that we dismiss
the exception on this issue for that reason. In maki ng this argument, which we reject, the staff has

Cite as 8 NRC 295 (1978)

CLI-78-19

UNITED STATES OF AMERICA
NUCLEAR REGULATORY COMMISSIONCOMMISSIONERS:
Victor Gilinsky, Acting Chairman
Richard T. KennedyPeter A. Bradford
John F. Ahearne
Docket No. 50-320

I n the Matter of
METROPOLITAN EDISON CO., et al.
(Three Mile Island Nuclear Station,
Unit No. 2)

September 15, 1978
Stating that it would conduct that hearing itself, theAppeal Board instructed the parties as to the data it
wished them to submit. ALAB-486, supra, 8 NRC at44-46. The Appeal Board made clear that thefurther hearing would result not only in a determination with respect to crash probabilities at future air
traffic levels, but also in a firmer finding with respect
to current crash probabilities than can presently be
made, owing to differences in the data bases andcalculational methods used in developing thepresent record. Finding that all data and analyses in
the record led to acceptable crash probabilities atcurrent air traffic levels, the Appeal Board ruled that
there was a reasonable assurance of no undue risk
to public health and safety from operation at thistime, and it declined to suspend the operating
license during the pendency of the reopened heari ng.
A petition seeking Commission review of ALAB486 pursuant to 10 CFR 2.786 was filed on August
8, 1978, by the representative of the Citizens for a
Safe Environment and the York Committee for a
Safe Environment. Since our review is not on thebasis urged by the petition, the petition is hereby
denied.

The Commission denies a petition for review of
ALAB-486, 8 NRC 9 (1978), but outlines additional
detailed data and analyses which the Appeal Board
should request when it conducts the hearing on aircraft crash probabilities directed by ALAB-486.
ORDER
In ALAB-486 (8 NRC 9), decided July 19, 1978,
the Atomic Safety and Licensing Appeal Board
reviewed the Licensing Board decision whichauthorized the issuance of an operating license to
the Three Mile Island, Unit No. 2, facility. A central
issue before the Appeal Board was the adequacy of
the record with respect to the probability of thecrash into the facility of an airplane heavier than
200,000 pounds. The Appeal Board found that therecord did not permit it to determine the future levelof heavy aircraft traffic-which is being monitored
under a technical specification in the operating
license-at which further protective measures (suchas reassessing structural design limits, restrictions
on air traffic patterns, redesign of exterior structures, and plant shutdown) must be taken, and it
directed a reopened hearing to address that matter.
305

As noted, the Appeal Board has indicated insome detail the information it considers necessary
for the reopened hearing. We believe that the
Appeal Board should request still more detailed data
and analyses. We have outlined in an attachment tothis order areas we believe should be pursued. The
Commission recognizes that the analysis will haveto be done on the basis of available data. Nothing inthis order should be construed as implying that calculations made in the absence of the full complement of data so outlined would necessarily be deficient.
It is so ORDERED.
For the Commission
Samuel J. Chilk
Secretary of the Commission

Dated at Washington, D.C.
this 15th day of September 1978.

Data and Analysis To Be Pursued in Further
Proceedings on
Three Mile Island Nuclear Station, Unit No. 2306

NUREG/CR-1250, Vol. II, Part 1