Corporate Profit and Nuclear Safety: Strategy at Northeast Utilities in the 1990s 9780691223827, 0691119945, 2004045861

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CORPORATE PROFIT AND NUCLEAR SAFETY

CORPORATE PROFIT AND NUCLEAR SAFETY

S T R AT E G Y AT N O RT H E A S T U T I L I T I E S IN THE 1990S

Paul W. MacAvoy and Jean W. Rosenthal

PRINCETON UNIVERSITY PRESS

PRINCETON AND OXFORD

Copyright © 2005 by Princeton University Press Published by Princeton University Press, 41 William Street, Princeton, New Jersey 08540 In the United Kingdom: Princeton University Press, 3 Market Place, Woodstock, Oxfordshire OX20 1SY All Rights Reserved Library of Congress Cataloging-in-Publication Data MacAvoy, Paul W. Corporate profit and nuclear safety : strategy at Northeast Utilities in the 1990s / Paul W. MacAvoy and Jean W. Rosenthal. p. cm. Includes bibliographical references and index. ISBN 0-691-11994-5 (cl. : alk. paper) 1. Nuclear industry—Northeastern States—Management—Case studies. 2. Nuclear industry—Deregulation—Northeastern States. 3. Nuclear industry— Northeastern States—Cost control. 4. Nuclear power plants—Northeastern States— Management—Case studies. 5. Nuclear power plants—Northeastern States—Cost of operation. 6. Nuclear power plants—Northeastern States—Safety measures. 7. Nuclear power plants—Northeastern States—Risk assessment. 8. Nuclear power plants—Environmental aspects—Northeastern States. I. Rosenthal, Jean W., 1945– II. Title. HD9698.U53N965 2004 333.792430974—dc22

2004045861

British Library Cataloging-in-Publication Data is available This book has been composed in Sabon Printed on acid-free paper. ∞ pup.princeton.edu Printed in the United States of America 10

9 8 7 6 5 4 3 2 1

Contents

List of Figures

vii

List of Tables

ix

Preface

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One Strategic Challenge at Northeast Utilities An Overview of Strategy and Performance at Northeast Utilities Two Northeast’s Competitive Strategy Visions of a Changed Future The Strategic Response Financial Conditions at the Beginning of the New Competitive Strategy Constraints: Price and Safety Regulation Alternative Strategies: Other Electric Utilities Cope with Threats of Deregulation in the Mid-1980s Comparative Nuclear Strategies: Pacific Gas and Electric The Northeast Competitive Strategy in Context—Was It at Inception the Dominant Strategy? Three The Nuclear Power Context for the New Competitive Strategy The Complexity of Nuclear Power Systems Safety Regulation at the Nuclear Regulatory Commission Self-Regulation in the Nuclear Industry Safety Culture and “Management Style” Cost Containment in the Context of Safety Regulation A Conceptual Framework for Analyzing Responses to Regulation Initial Results: The 1990–91 Millstone Nuclear Plant Shutdowns Nuclear Regulatory Commission Early Warnings The LRS Report and CT DPUC After-the-Fact Appraisal

1 2 7 8 10 13 18 22 26 27

31 31 35 37 38 41 45 48 53 57

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Strategic Focus: Acquisition of Public Service of New Hampshire Initial Results: Financial and Nuclear Plant Operating Performance Four Revisiting Competitive Strategy in the Mid-1990s Northeast Strategy and the Competitive Threat The PEP Process for Improving Nuclear Plant Performance Operating Problems at Millstone in 1993 The Strategy of Northeast and the Board of Trustees The Financial Success of Cost Containment Strategy and Management Compensation Another Look at Alternative Strategies

57 61 64 64 73 75 79 80 83 86

Five Northeast Strategy and Regulatory Shutdown of the Millstone Plants Failing Operations at Millstone Shutdown at the Millstone Site Increasing Public Concern The Role of the Board in the Northeast Utilities Collapse CODA: The End Game Strategy as the Cause for Shutdown

88 88 97 98 101 105 108

Notes

113

Bibliography

135

Index

147

Figures

3.1. The Nuclear Station Learning Process

41

3.2. Hazard Functions for IND and SEV Distributions

47

5.1a. Events and Causal Factor Chart, Prepared by Northeast Utilities as Part of Root Cause Investigation, p. 1

95

5.1b. Events and Causal Factor Chart, Prepared by Northeast Utilities as Part of Root Cause Investigation, p. 2

96

5.2. Scheduled and Forced Outages

97

Tables

2.1. Northeast’s Competitive Response Strategy

12

2.2. Northeast Utilities Consolidated Financial Performance (millions of dollars)

14

2.3. Northeast Utilities Statistics on Financial Performance

15

2.4. Northeast Utilities Consolidated Sales and Operations (millions of kilowatt-hours)

16

2.5. Northeast Utility Nuclear Plant Capacity as of 1988

17

2.6. Construction Costs of U.S. Nuclear Facilities

18

2.7. New Strategy Proposed by Electric Utilities 1985–90

23

3.1. The Millstone Nuclear Plants

42

3.2. Northeast Utilities’ Estimates of Functional O&M Savings under Its Competitive Response Strategy (millions of dollars)

44

3.3. Nuclear Expenses for Millstone Facilities Adopted in CL&P’s Rate Case (thousands of dollars)

45

3.4. Plant Performance / Nuclear Capacity Factors (percent of available capacity in operation per year)

51

3.5. Plant Outages at Millstone Plants (days / years)

51

3.6. Nuclear Regulatory Commission SALP Scores for Millstone Site Nuclear Plants

54

4.1. Northeast Utilities Sales and Revenues (millions of dollars)

69

4.2. Cost of Power Generation and Capacity Availability of Potential Competitors

71

4.3. 1995 Marginal Costs of Power Generation at Northeast Nuclear Plants (cents per kilowatt-hour)

71

4.4. Northeast Utilities Consolidated Financial Performance, 1991–95 (millions of dollars)

81

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L I S T O F TA B L E S

4.5. Northeast Utilities Statistics on Financial Performance

82

4.6. Comparison of Northeast Utilities and 28 Large Electric Utilities

83

4.7. Total Compensation of Senior Executives of Northeast Utilities, 1991–97 (thousands of dollars)

85

4.8. Diablo Canyon Power Plant Operations and Earnings

87

5.1. Northeast Utilities Consolidated Financial Performance (millions of dollars)

103

5.2. Northeast Utilities Statistics on Financial Performance

103

5.3. Northeast Utility Financial Performance, 1988–98

105

Preface

IN A MAJOR article on November 20, 2002, the New York Times stated that a confidential report to a nuclear power plant safety organization warned that electric utilities had switched strategies to “focus on production over safety” and had “endangered” the Davis-Besse nuclear plant in Ohio.1 The trade-off in favor of reduced costs or increased running time, and against plant maintenance or downtime, “could be a broader problem around the nation.” The Times said that the Ohio plant operators had demonstrated “excessive focus on meeting short-term production goals” and “a lack of sensitivity to nuclear safety.” This was not the first such report; trade-offs leading to safety issues in plant operations had been noted in a number of companies, including Northeast Utilities during the first half of the 1990s. Our greatest interest is not the technology of safety, but how that trade-off of management targets and safety may be part of corporate strategy. In the mid-1980s Northeast Utilities, the largest electricity generating and distribution company in Southern New England, adopted a new cost-containment strategy with the goal of becoming the low-cost power supplier in its soon-to-be competitive and deregulated power markets. For a decade it carried through that strategy in the face of increasing employee, regulatory, and public resistance to cost cutting at its nuclear power generating plants. Management achieved a significant measure of its strategic goals in that decade, including most if not all of its budgetary goals. But this implementation program involved costcutting in key areas of nuclear plant maintenance and equipment upgrades, which involved a trade-off that put the company’s three nuclear power plants at Millstone Point (on the Connecticut coast) at greater risk of operational problems and being shut down by the Nuclear Regulatory Commission. This forced shutdown took place in 1996, when the Nuclear Regulatory Commission ordered the three plants, which were all out of service, not to restart. After the company spent many millions of dollars on renovating these facilities and retraining the staff, one plant was closed permanently and two were relicensed as if they were new startups. Northeast as a corporation admitted to criminal charges on certain high-risk operating practices. Subsequent to relicensing, the nuclear plants were auctioned off and ownership transferred to another generating company. New management now runs the remaining parts of Northeast as an electricity transmission and retail distribution utility.

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What can we make of this “competitive” strategy? This could be just another case of corporate bad luck, caused by undertaking excessive risk, compounded by bad timing in plant accidents and equipment failure, resulting in the worst-case result. An alternative explanation is that management’s pursuit of cost-containment strategy, with its compensation targeted on lower plant costs, inevitably led to degraded reactor operations, even as the best-case result. According to this explanation, the competitive strategy of Northeast Utilities from the mid-1980s to the mid-1990s increased the risk of future plant failure as a favorable tradeoff for more immediate corporate net income and executive compensation. Our inquiry is whether a competitive strategy to achieve target profit and compensation goals necessarily puts the company on the line for nuclear shutdown. In the chapters that follow, we examine the month-to-month operations of the company through phases of development, implementation, and response to a new strategy at Northeast from the mid-1980s to the mid-1990s. We collect evidence for testing an “ordinary” explanation or hypothesis for undertaking such a strategy, by which the company took on a more promising plan for achieving growth in earnings, but with increasing risk that its nuclear plants would not operate to their previous high level of performance. This explanation holds that management in the 1980s had undertaken cost containment and achieved significant improvement in corporate financial performance, but by the early 1990s it perceived that cost containment had created a serious risk of forced outage in its nuclear operations and was working for reversal. The reaction of the Nuclear Regulatory Commission caused Northeast to take remedial steps to return the Millstone plants to the operational levels achieved in the early 1980s. Under this theory, an NRC-ordered shutdown in the mid-1990s was a premature “accident” of regulation. We also collect evidence for an alternative explanation or hypothesis to the effect that management continued pursuing cost containment, at increasing risk of shutdown, to achieve more aggressive profit and compensation targets. This “extended risk” hypothesis has it that management, for its own advantage, carried out a strategy that was too risky to benefit the corporation. The fault lay with governance. Management was controlling, when it came to the determination and the evaluation of results from strategy, against the interests of investors, who would not have placed such a priority on current earnings and executive compensation. If there is evidence for this explanation, it is that management sustained and benefited from cost containment through the mid-1990s, even in the face of increased regulatory threat of shutdown, in order to produce those high earnings. Our research cannot provide a definitive conclusion as to which expla-

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nation is exactly accurate. In describing performance, however, the “ordinary” explanation has it that management tried to return the company to safe operations, while the “extended risk” explanation is that management in its own interests took on numerous operational failures that involved an increasingly unacceptable risk of regulatory-imposed shutdown. Short of reading the minds of management, determining which explanation is more descriptive can be at least partially based on the corporate record on budget decisions, responses to changes in plant performance, and responses to regulatory findings of operating violations. The conclusion is the reader’s to make. The story presented here will not have an impact on current Northeast Utilities management. The Millstone facilities and other Northeast nuclear sites, whether operational or permanently shut down, are in the hands of other owners. Current management of Northeast did not come on board until after the events described in this study. Management teams and boards of other nuclear-based power companies, and of other industries with hazardous operations, however, face strategic choices similar to those encountered by Northeast in the decade of 1986 to 1996. Illuminating the specifics of this series of events may provide a useful lesson, if not a cautionary tale. An extensive search on our part in nonconfidential documentary materials of the Nuclear Regulatory Commission and the Connecticut Department of Public Utility Control provided the record on corporate decisions found in this book. Key documents on the company’s strategy were available from these sources, making it possible to develop a moreor-less complete narrative on performance in implementing strategy from 1986 to 1996. The Nuclear Regulatory Commission (NRC) maintains records on official communications with management of companies with nuclear power plants. The commission requires multiple levels of reporting by these companies on their plant design and operations, from fact finding on unusual occurrences in operations, to worker complaints regarding hazardous conditions in plants. At the time of our search, the commission documents were available for public access in Washington, D.C., on its website, and on microfilm in libraries throughout the country. In particular, documents related to Millstone facilities were available in its Connecticut depository. (After September 11, 2001, some of those sources were restricted.) In its role as state regulator of public utility company prices and service offerings, the Connecticut Department of Public Utility Control (DPUC) held extensive proceedings on what went wrong at the Millstone nuclear plants in the mid-1990s. In addition to its own decisions and reports, the Connecticut DPUC maintained copies of documents that the

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company had provided in response to DPUC data requests during those proceedings. Although some documents deemed confidential by the company were not available for public review, almost all those describing corporate strategy were available for inspection at the DPUC’s repository in New Britain, Connecticut. No confidential corporate documents were used in preparing this study. Beyond these regulatory files, the problems at Northeast were aired in public, with legislative proceedings, newspaper reports, and media commentary. We first became familiar with the issues and the record after the 1996 regulatory shutdown, when preparing a report for the nonoperating owners of Millstone Three, on alleged malfeasance of Northeast Utilities in operating this facility. While the research literature on risk management in nuclear-plant operating strategies is limited, we used the website of SSRN (the Social Science Research Network) to source university and national laboratory studies that were relevant. We were introduced to the literature on hazard theory by Professor Li Gan of the University of Texas (Austin) and through many discussions of alternative hazard functions with Dmitry Shapiro, an econometrics graduate student in Yale’s Department of Economics. In addition to documents directly related to Northeast Utilities, the public record contains information on the strategies of other utilities related to the management of profit and risk in nuclear reactors. We have called on this record to study the management of PG&E’s Diablo Canyon nuclear facility in California. Correspondence with faculty and staff at the University of California who were investigating nuclear operations and management practice at Diablo Canyon provided us with additional insights, for which we are grateful. In spite of these efforts, our knowledge of the events and problems of diverse strategies at Northeast reached certain limits. We did not have access to confidential company directives on cost cutting in specific plants, nor did we have the opportunity to review company five-year plans during the first half of the 1990s. Given these limitations, information that would have completed our investigations of the two hypotheses was lacking. We leave the reader with the task of judging the evidence here as to how “deliberate” Northeast’s management plans, programs, and projects to contain costs in nuclear operations were in bringing Millstone plant operations to regulatory shutdown in 1996. We have had the sustained financial support of the John M. Olin Foundation grant to the Yale School of Management for research in government-business relations. We note with regret and understanding its closing; the foundation was a powerful force in law and economics research in the last quarter of the twentieth century, and it will be missed. Our colleague Dr. Nickolay Moshkin helped with database and regres-

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sion analysis of corporate profits, as did Olin Foundation Research Fellow John Bodt. Dmitry A. Shapiro provided invaluable insight on hazard functions and statistical modeling. Professors Ivo Welch and Jonathan Feinstein of the Yale School of Management provided valuable comments during our presentation of an early draft to a Yale faculty workshop. Listed on the Social Science Research Network, the working paper version of this book was one of the ten leading downloads in its classification, and we received many email comments and suggestions, for which we are grateful. Professors R. Preston McAfee of the University of Texas and Geoffrey Rothwell of Stanford University first provided editorial appraisals for Princeton University Press and then in subsequent rounds gave us substantive and detailed suggestions for improving the content and direction of the manuscript; we are grateful and even at points humbled by their analytical insights and erudition in hazard analysis as well as in corporate strategy. We wish to thank Sharon Krischtschun and Jessica Lather for their word processing and management of project assistance throughout the five stages of development, which required not only patience but also real enthusiasm for what we were doing. We dedicate this work to Kay MacAvoy and Erik Rosenthal, who did their best to sustain our effort, challenging as that has been, from beginning to end. Paul W. MacAvoy Jean W. Rosenthal Yale School of Management

CORPORATE PROFIT AND NUCLEAR SAFETY

One Strategic Challenge at Northeast Utilities

In the early 1980s Northeast Utilities was one of the country’s leading electric generating and distributing companies, with a reputation not only for service but also for technological leadership at its nuclear plant operations, including those at the Millstone site. By 1996, Northeast’s Millstone nuclear facilities were shut down by the Nuclear Regulatory Commission, requiring the utility to incur extraordinary expenses for repairs, staff retraining, and replacement power. The state utility regulatory agency denied the company the opportunity to recover these costs from customers and, as a result, Northeast’s stock price collapsed. Its reputation as a technological leader in power generation was destroyed, as management pled guilty to twenty-five felony charges brought against its operations of the nuclear facilities. By the end of the 1990s, the company had its assets up for sale to independent wholesale power producers and other retail distributors, in effect seeking to disappear from the electric power scene. What happened in ten short years to bring about the destruction of this company? There are conflicting answers, many of which were voiced in public hearings and court proceedings in the aftermath of the shutdown. The company’s defenders argued that it could not respond to abrupt and arbitrary changes in nuclear safety regulation at a time when it was responding to newly competitive markets for its products and services. Part of this explanation is that an unfortunate series of operational accidents in the nuclear plants contributed to its downfall. As its regulated markets were becoming subject to deregulation, costs of production would become a central issue in maintaining Northeast’s position in New England. The company cut costs, then stated it was surprised by plant accidents. This strategy’s increased risk, said to be limited, turned out to be realized not because of excessive cost cutting but just bad luck. This explanation, however, is not the only answer to the question as to why the company collapsed. An opposing theory is that management, dedicated to a competitive strategy designed to deal with regulatory change, made decisions to contain costs that deliberately took on extreme risk of safety-related violations of nuclear regulatory standards. They did this to sustain implementation of a “cost dominance” strategy to achieve the company’s immediate targeted positions of substantial

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growth of revenues and earnings. This “enhanced risk” theory posits that the destruction of Northeast was strategic: cost containment necessarily interacted with nuclear plant operations to take on enhanced risk, including that of regulatory shutdown, which then occurred, but not before the goals had been achieved to enhance the earnings of those in charge. Why did management depart from the company’s best interest in responding to such risk? When this trade-off is viewed from a management perspective, bonuses and stock awards tied to current earnings do not reflect potential additional costs in the future. The only current costs of the strategy to management were those associated with the increasing pressure inherent in complaints of the Nuclear Regulatory Commission. From the point of view of management if not the company, these potential returns of continuing cost containment could be “worth” the risk of degraded nuclear safety.

An Overview of Strategy and Performance at Northeast Utilities From its inception Northeast had a challenging mandate in delivering electricity to industrial, commercial, and residential customers. Its retail services were regulated by state public utility control agencies in Massachusetts and Connecticut under certificates allowing exclusive operation in its distribution regions. As a regulated monopoly, its tariffs of charges and conditions of sale were approved by these agencies when found to be “just and reasonable;” the company had the opportunity, but not the guarantee, to operate profitably in a growing market as long as it did not exceed allowed levels of “just and reasonable” profit. Its second and equal challenge consisted of conforming to nuclear-power-plant safety requirements in operating licenses granted by the Nuclear Regulatory Commission. The commission determined that plants were “safe and reliable” when operated according to certified design, based on frequent inspections and reviews of plant equipment, staff, and system operations. Within this framework of price and safety regulation, the company, according to its charter, was intended to generate allowed and achievable earnings for its investors. Prices were fixed, based on a predesignated rate of return on capital, but if costs could be reduced below expected levels and if demand were to increase beyond forecast levels, then earnings could go higher. That is, senior management had the responsibility to generate and distribute electricity at prices set by state regulators, while conforming to plant safety regulations, and providing investors with the highest (constrained) return possible on their capital. The board of directors of the company, termed at Northeast the Board of Trustees, had the responsibility to appoint, monitor, and evaluate management on

S T R AT E G I C C H A L L E N G E

3

these aspects of performance and ultimately on the achievement of investor returns that perpetuated the company. It was within this framework that Northeast Utilities developed a new strategy to attain a competitive advantage in sales of electricity in New England in the mid-1980s. Located in industrialized areas of southern New England, with more than half its capacity in advanced nuclear generation plants, Northeast Utilities’ prospects for growth in both sales revenues and total profitability depended critically on maintaining its position as the dominant power supplier in a growing regional market. A major shift, however, was expected to take place in the regulatory mandates facing management and the board of directors. At some point in the future, deregulation of entry and price control in generation markets would open them to competitive sources of electricity. Bulk power of other generating companies was expected to be brought into southern New England over common transmission lines, even over Northeast’s own transmission lines. To respond to this “competitive threat,” Northeast management adopted a new strategy in the mid-1980s, with the goal that Northeast would become the low-cost provider in its service region, not only to retain but also to expand its share of electricity markets. In 1984 Northeast electricity sales increased by 3.9 percent, net income by 46.5 percent and, earnings by 34.7 percent.1 The company’s nuclear generating units had achieved a composite operating rate of 78 percent of capacity, comparable to that of the leading nuclear generating companies nationwide. In 1986, Northeast completed construction of its most technologically advanced nuclear facility, the 1,150-megawatt Millstone Three, and placed that plant in commercial service with a first-year capacity factor of 84 percent.2 This high-level performance led to enhanced earnings and historically high stock-price levels; looking ahead, Northeast expected to sustain these capacity factors to increase sales and earnings significantly without adding to existing plants for the next twenty years.3 A little over a decade later, Northeast Utilities was in operational and financial shambles. The Nuclear Regulatory Commission had shut down the three Millstone nuclear plants, with the requirement that hundreds of millions of dollars had to be invested in renovation before they would be allowed to restart. The shutdown had followed regulatory commission, employee, and media accusations of corporate failure to manage these facilities safely.4 Operationally, the forced Millstone shutdowns ended the company’s history of profitable performance. Northeast had to purchase electricity to replace that of the shut-in nuclear plants, rebuild these plants to meet stringent restart requirements, and recruit or retrain plant operators who could pass new competency tests of the safety regulatory agency. The

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result was an increase in costs in nuclear operations that eliminated company-wide earnings. The Northeast common stock share price in 1996 fell to 20 percent of the 1986 level.5 Northeast Utilities’ nuclear operations were taken apart and reassembled because of the NRC shutdown. The oldest of the three shut-in nuclear plants, Millstone One, was not reopened but instead began the long and costly process of decommissioning, ensuring that it would never again generate either energy or income. The newest of the plants, Millstone Three, reopened after twenty-six months of extensive reconstruction, while Millstone Two opened after an even longer period. Under the decisions of the Connecticut Department of Public Utility Control, the restructuring costs were not passed through for recovery in utility rates, nor were the costs for replacement power; both were absorbed as losses by investors. The Northeast losses not only were operational and financial but also included destruction of the organization that had existed in the early 1980s. The United States Attorney for the District of Connecticut undertook an investigation that led to charging Northeast Utilities with criminal violations of regulations in nuclear operations. Northeast Utilities pleaded guilty in 1999 to twenty-five felony violations of environmental and safety regulations at its Millstone power plants between 1994 and 1996 and paid a fine of $10 million. Of the total, $5 million was related directly to nuclear operations, the largest fine in the history of the Nuclear Regulatory Commission’s regulation of commercial nuclear power facilities.6 In December 1999, Consolidated Edison of New York made an offer to acquire Northeast, which, when completed, would have provided Northeast shareholders with cash and stock. The merger offer put a negative value on the Northeast nuclear generation assets, given that the value of the assets to be acquired was $131 million more if the nuclear assets were excluded. The merger offer was withdrawn early in 2001, after Con Ed refused to accept the risk of Northeast’s fixed-price contracts for future power deliveries.7 An auction of the Millstone plants was announced in April 2000 and completed the following July; the successful bidder for the relicensed plants opened Millstone Two and Millstone Three under new strategies and management. Northeast continued as a retail distribution and transmission company, eventually eliminating all its nuclear- and fossil-generating operations.8 Given that “performance” is measured in returns to shareholders in the long run in perpetuation of the enterprise, these results were catastrophic. Northeast had gone from being a profitable producer and distributor of electric power to a local retailer that distributed power purchased from others. Its destruction of shareholder value made the company a target for takeover; but with the collapse of its sale to Con Ed, it was an independent enterprise only because its contracts made it uneconomic to purchase.

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This outcome of Northeast’s strategic approach is not as catastrophic as, for example, a destructive accident at a reactor would have been. As the NRC made clear after Three Mile Island, however, safety as defined for operators of nuclear facilities is not an all-or-none proposition. While no level of spending could totally remove the risk of a nuclear shutdown accident, spending had to be extensive enough to make the plant operate without “frequent” or “serial” forced shutdowns from malfunction. That level of spending was inherent in meeting NRC high-grade requirements in its inspection and review process. NRC complaints made it clear that Northeast took on excessive risk by operating outside its parameters for plant spending, which the NRC took as the foundation for safe operations. In examining management decisions, it is useful to conceive of them as sequential decisions unfolding over time (i.e., a simple “decision tree”). In 1986–87, Northeast management and the board considered alternatives and made an initial choice of a strategy that was the first “yes” branch of the tree. At a point four years later, the effects of implementation of that strategy become clear, and the choice of which branch to proceed on was the choice to continue or abandon the strategy. Given regulatory agency objection to continuing the strategy, the choice was either to continue or to return to pre-strategy levels of investment in maintenance in the Millstone plants. Did this company make decisions to continue, and thus follow the “enhanced risk” theory? If so, for what purpose? The response to these questions is the subject of the chapters that follow. Chapter 2 develops the Northeast competitive strategy of the latter half of the 1980s. We evaluate this strategy against alternatives available in its regulatory environment. Chapter 3 provides a narrative on the implementation of that strategy and introduces the emerging conflict between that strategy and nuclear plant safety in operations, as defined by the Nuclear Regulatory Commission and industry self-regulation standards. It then describes the severe setbacks in operational and safety performance from forced outage in the Millstone nuclear plants in 1990 and 1991. These required Northeast to make basic decisions on backtracking strategy, as the NRC openly questioned the safety and reliability of Millstone plant operations. If the company abandoned implementation of the strategy, then costs would increase, but nuclear plant performance would likely improve. If Northeast still pressed hard to achieve strategic cost containment, then nuclear plant performance would not likely improve. The narrative does not make clear which path was taken at that point, because of complexities caused by the acquisition of another nuclear plant, as part of the overall competitive strategy. Interactions with the Nuclear Regulatory Commission related to the acquisition caused the company to increase operations and maintenance expenditures of all its nuclear plants.

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Chapter 4 describes cost containment in the first half of the 1990s, with enhancements required for NRC approval of the new plant acquisition. Signals coming from the commission increased to the effect that the Millstone plants would be put on the “Watch List” for regulatory shutdown unless there were improvements in plant performance. Chapter 5 describes extensive forced outages at Millstone in 1995 and 1996, and then, with all three plants down, the NRC orders that prevented Northeast from restarting the plants. In the end, increasingly frequent operational problems, carried over from previous years, increased the likelihood that the regulatory agency would impose shutdown. When the opportunity arose for the NRC to decree that the plants could not reopen without extensive evaluations and additional investment, then it did so. Northeast’s failure, at that point, was caused by forced outages that by chance had all three plants down at once. But this performance itself requires an explanation. Underlying it is the failure to modify or cancel the corporate strategy. To be sure, that strategy was “adjusted” somewhat in response to increasingly negative reactions from utility regulators, plant employees, and ultimately the safety regulator. Adjustment, however, was not abandonment; the strategy was still the priority of management, even as the company was warned of an imminent shutdown at Millstone. In accord with the “ordinary” theory, in seeking to maintain “halfway” strategy, management operational behavior was still at odds with regulatory standards; in accord with “enhanced risk” theory, management took on more risk by ignoring the NRC to achieve full cost containment for its own sake. One of these explanations must be correct. There is no evidence of incompetence. Management and the board of directors were able to manage a complex three-reactor facility under extremely high levels of regulatory control and achieve a high level of plant security; it had done so at a more difficult time of initial plant operations in the 1980s. Either management and a passive board of directors maintained what they thought was a moderate risk strategy, or else they maintained a high-risk strategy, for good reason. We test the “enhanced risk” hypothesis to the effect that it was to management’s specific advantage to go as far as it did in the face-off. The test of this theory appears in chapter 5. We find that the system of rewards for management focused on year-ahead corporate earnings, which were substantially unaffected by increasing risk of a Millstone shutdown in the future. The result was that the increases in risk-to-reward ratio for the company facing shutdown constituted only limited changes adverse to a management that focused on next year’s sales and earnings performance.9 The strategy that was actually put into effect had more risk of shutdown but was not adverse to management until the last few months of its ten-year duration.

Two Northeast’s Competitive Strategy

Northeast since its inception had been protected from competition by the exclusive franchise territory granted by the Connecticut and Massachusetts regulatory agencies. As the exclusive provider of service at retail to corporations and households, Northeast had little need for a strategy designed to create an advantage over competitors. In the 1980s, anticipated regulatory reform proposals in both federal and state legislation presaged the erosion, if not destruction, of the “regulatory compact” with the sole source supplier. Northeast along with most other electric utilities began a search for strategies for gaining a competitive position among numerous generation companies and brokers that would deliver power to any customer in the now no-longer exclusive territories. The key to a competitive advantage was the relative cost of generation, transmission, and distribution. Northeast’s high-cost nuclear generation placed it at a serious disadvantage. Moreover, unlike many other utilities, it saw this shift to a position of competitive disadvantage as likely to take place in the very near future. Northeast perceived as early as 1985 the need to develop a new strategy to lower the cost of production at its existing capacity for it to sustain its position in New England markets. With new management and the assistance of leading consultants, Northeast developed a focused competitive response and put it into place rapidly in the mid-1980s.1 The focus was on cost reductions in all divisions of the company, at different rates in different divisions, but designed to meet a goal of deep overall cuts. The cuts were as deep as required to meet the competitive cost level for power in a New England–wide market. There were acknowledged risks in undertaking deep cuts in operations costs; because this was a highly sophisticated exercise, however, the risks were to be managed in the process of achievement of specific cost levels. The formation of this strategy is worthy of extended discussion. First, this strategy posed solutions to the many problems of adjusting to competition in an industry subject to sixty or more years of franchised monopoly. Second, it did so by taking an extreme position—that of making deep cuts in current costs in plant operations and maintenance in the highest cost operations. Going from last to first in cost efficiency, as the

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baseline in a turnaround strategy, is a daunting task for corporate management and governance. It has not often, if ever, been tried elsewhere. The test for validity of such a strategy, on its face, is whether it makes sense analytically. Those involved in strategy formation at Northeast based their determination of a trade-off of lower costs of maintenance and operations for more frequent occurrence of operational problems (in this context, of forced plant shutdowns for systems failures). Did the management, board of directors, and consultants, in decisions leading to an extended risk of these hazards, produce a Northeast strategy that passed the test of making sense? The answer here is preliminary, based solely on empirical evidence on how the company formulated the strategy, and on our conception of the return-risk trade-offs. The second and more definitive test, the history as to how the strategy worked out in the 1990s, follows in the succeeding chapters. Even at the beginning, a “low-cost dominance” strategy may not have been the best choice for the Northeast competitive response. It was not the only option, and its choice may have been unduly aggressive as to the timing and extent of competitive entry over the next two decades. Northeast had a history of achieving profit rates equal to or in excess of its costs of capital, while maintaining positive ratings from both utility and safety regulators. If it had not acted as though competition were pounding on the door, it could have gradually implemented a new strategy while phasing out the old nuclear capacity, within the regulatory framework of protected prices from the state utility commissions and high safety ratings at the Nuclear Regulatory Commission. Most other utilities saw this alternative as better for the company in the long run—to develop a competitive response only when competition was presaged by actual signs of entry by other generating companies seeking to bring power over Northeast transmission lines. It may have been too early for a full response of the kind Northeast proposed.

Visions of a Changed Future In the mid-1980s Northeast Utilities took the position that the company would face significant competition within the next five years, as its large customers gained access to cheaper power from generating sources outside of New England. The providers of the cheaper power would “wheel” that power over Northeast’s transmission grid to the facilities of the end-use customer. In an early phase of deregulation, new rules governing transmission would be likely to require Northeast to open its grid to other wholesale power suppliers. Open transport had been established in other partially deregulated network industries, including gas transmis-

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sion and long-distance telephone service. The utilities were beginning to experience competition in generation from their large industrial customers, who sold back to the utilities the electricity that they (the customers) produced as a byproduct of the steam generated in industrial processes.2 The next phase would be agency deregulation of franchise licenses to allow low-cost power sources outside of New England to wheel in power supply below local utility prices. It was acknowledged that when the time came, power sources in the mid-Atlantic region would be able to offer Northeast’s retail customers wheeled-in supplies at prices below those that Northeast could offer for generation from its nuclear generating plants. Although both the rapidity and the extent of such incursions into its service region were uncertain, Northeast acted in the mid-1980s as if it believed that such entry would take place soon. Northeast responded to this “competitive threat” with urgency, given that its high-cost generating capacity made its wholesale and retail sales of electricity vulnerable. The company had nuclear plants of varying vintages, all with relatively high costs of operation. The oldest was Connecticut Yankee, which had been in service twenty years, while Millstone Three had just come into service at the end of 1986. With that plant on line, nuclear generation provided 68 percent of Northeast’s electrical power supply. With a total generation capacity of 5,756 megawatts, including both fossil and nuclear sources, Northeast provided almost 30 percent of the power in the New England Power Pool during the record-setting 1988 summer peak. In an average year, Northeast would supply more than 20 percent of the regional demand for the peak period and had more than sufficient power to supply its own customers.3 Northeast had been able to contract out 3000 megawatt-years of its supply to other retail service providers in 1988. These contracts were relatively short term, so that when delivery was complete Northeast would have that much excess capacity. As an indication of the emerging problem, a 1988 decision by the Connecticut Department of Public Utility Control (DPUC) noted that the major Northeast retail subsidiary had “significant excess capacity,” only part of which could be utilized for sales to other regional utilities.4 These other utilities had the potential for substitution of their supplies specifically for Northeast’s high-cost nuclear production. Northeast had to expect that, as the source of high-cost power in an emerging regional market, it would lose sales to lower-cost kilowatt-hours from other companies. And independent (nonutility) producers were building capacity as well. While they had supplied only 2 percent of regional requirements in 1988, Northeast expected supply from those new sources to grow to more than 13 percent by the early 1990s. In the polite language of an-

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nual reports, Northeast noted, “much of this privately owned capacity will come into service ahead of the need for new supply resources.”5 As the high-cost provider of power in oversupplied markets, Northeast foresaw the erosion of its ability to recover its investment through a continued high level of power generation.

The Strategic Response Northeast determined that it had to have an aggressive strategy to sustain a competitive position in the New England market over the next five to ten years. It retained a leading energy consulting service, McKinsey and Company, to assist in formulating the new strategy. The McKinsey firm would work closely and at length with the senior management—the CEO of Northeast was from McKinsey, and had been a consultant to Northeast while at McKinsey. Northeast paid $1.022 million to McKinsey in 1987, the second year of its strategy development program, to assess Northeast Utilities’ competitive threats and opportunities and to develop its cost reduction initiative.6 The McKinsey-led formulation of the competitive challenge was described in the 1988 Northeast Annual Report as follows: In 1987, an extensive study identified self-generation by large industrial and commercial customers, cogeneration facilities, and competition from other utilities for wholesale customers as significant factors posing a threat to the company’s existing energy market . . . with a potential loss of as much as twenty percent, approximately 750 megawatts of its operating subsidiaries’ electric load, by the early 1990s.7

With this view of the future, management proposed an aggressive strategic response. In “Strategy to Meet Competitive Threat,” delivered on October 23, 1987, Northeast President Bernard Fox described the new strategy to key employees. The focus was on extensive cost containment with a target of a 12 percent reduction below projected costs by 1990, based on a 7 percent reduction in operations and maintenance costs company-wide and a 13 percent reduction in costs in Nuclear Engineering and Operations.8 Mr. Fox outlined cost-reduction targets year-to-year, beginning with those in the 1988 budget commencing within two months from the date of his presentation. The employment level was to be cut from 9,862 in 1987 to 9,410 employees in 1988. Total non-fuel operations and maintenance costs across fossil and nuclear plants were to be reduced from $802.4 million without “cost management,” to $745.0 million with “cost management.” These cuts were company-wide, but Nuclear Engi-

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neering and Operations was to be cut by a greater percentage than other functional groups.9 Deep cuts in nuclear operations were said to be justified. The presentation cited a study by in-house nuclear staff comparing Northeast’s nuclear generating costs to those of twelve comparable plants in the industry. The comparison implied that Northeast nuclear generation was overspending, given that these other plants had lower operation and maintenance costs per kilowatt-hour of produced electricity. Northeast was to “benchmark” operation and maintenance costs, and to reduce Millstone costs specifically by 13 percent. This part of the strategy was the most aggressive. Extending cost containment that far in the nuclear facilities had a number of implications. Nuclear was responsible for a large percentage of operation and maintenance costs, so that cutting costs there would contribute most to meeting company-wide goals for cost reduction. Further, management sought to cut costs more in nuclear than in other areas because it viewed the nuclear plant operations as relatively inefficient. In their view, the operations of the nationwide “best” nuclear plants, at lower cents-perkilowatt-hour cost, demonstrated that Northeast facilities were being “over-maintained.”10 The impression from this presentation is that the management of Northeast Utilities planned to undertake cost containment in its nuclear operations as a priority, even the highest priority. The presentation included a slide entitled “Activity Value Analysis,” showing “Objective 1, Reduced Expenses,” outranking “Objective 2, Excellent Service.” It posed a series of “Questions about Activities We Currently Perform,” asking, “Could we: do it less often? Stop doing it? Reduce the quality? Have someone less skilled do it? Automate it? Do it differently? Centralize / decentralize it? Make or buy it? Combine it with something else?”11 The cost containment portion of the competitive response strategy set targets for cuts in operation and maintenance expense, and in investment in replacement equipment, without specifying implications for the reliability of plant performance. The targets were provided in broad-brush language in the Northeast Utilities 1987 and 1988 Annual Reports as the “Strategy for Profitability in Public Service.” The 1987 Annual Report stated at the outset, “planning for the future in the face of rapidly expanding competition was a top priority item on our management agenda during 1987.”12 The 1987 report also featured an article by consulting energy economist Dr. Charles Cicchetti that expanded on and dramatized this theme, entitled “The New Competitive Battlefield: A View from the Trenches.” Cicchetti stated that earlier forecasts of large annual increases in demand were grossly inaccurate, and regulators were not allowing increases in construction costs to be passed on in rate increases,

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so that earnings prospects were in decline. He also pointed to an increasing ability of large customers to construct “PURPA machines” (referring to the Public Utilities Regulatory Policies Act; see note 2) to produce their own electricity as “utilities were peering over the edges of their foxholes” at those customers leaving the system.13 The following year, in the 1988 Annual Report, William Ellis, Chairman and CEO, and Bernard Fox, President, presented the new strategy in detail. The report began with a description of the impending “competitive threat,” centering on the potential loss of 20 percent of the load by the early 1990s. It outlined the following response: Management has implemented a strategy to mitigate this threat. The strategy includes a marketing plan to enhance customer service and improve energy efficiency, an aggressive cost management program to hold down electric prices, and working with regulators to reduce the nonresidential-customer subsidies to residential customers provided by current rate design.14

This extended version was intended to increase competitiveness by “reducing costs, improving customer service, and seeking more competitive rate structures through the regulatory process.”15 The four-part program, as outlined in table 2.1, called for reducing costs in an effort to reduce prices to industrial customers, who most likely have competitive alternatives. Retail prices to residential consumers could be reduced only if the

TABLE 2.1 Northeast’s Competitive Response Strategy Northeast’s Four-Part Strategy

Corporate Implementation Items

1. Increase competitiveness of NU’s core business

• cut operating and capital costs • improve customer service

2. Improve financial performance

• establish more competitive rates • increase revenues and earnings margins from Part 1 • restructure debt holdings

3. Expand geographically and focus on electric business

• acquire electric production and distribution outside Southern New England • divest natural gas distribution

4. Enter new energy-related businesses

• set up new corporate structure for new unregulated service offerings

Source: Northeast Utilities, 1988 Annual Report, pp. 2–8.

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shift of distribution costs from industrial to residential buyers was more than offset by cost decreases from overall containment and cuts in operations. This put pressure on plant operating and maintenance outlays. Management in 1988 reported that “results of cost-cutting and expensereduction activities have been impressive, [with] functional operating expense budgets reduced well below 1987 levels, [and] our workforce reduced by more than three hundred authorized positions.”16 The cost-cutting programs were to continue in that direction and to that extent for the next three years. Less progress was made in changes to rate design, since “disappointing Connecticut and Massachusetts rate case decisions had not reduced the cross subsidy from business to residential services.” As part three of the strategy, Northeast proposed to expand geographically and had made a significant move in that direction with its proposal to acquire Public Service Company of New Hampshire. In attempts to diversify, as part four of the strategy, by entering unregulated energy-related businesses, the company had established a subsidiary to invest in cogeneration, but this had not yet led to a specified level of investment.17 Thus, while the strategy had four parts, all that had been implemented at the initial stage was cost containment. The Northeast Board of Trustees had the authority and responsibility to approve corporate strategy, and should have been in the forefront of developing this wide-ranging, indeed revolutionary, focus on cost containment. The board received a presentation describing the strategy. They signed the 1988 Annual Report and were present for its presentation to shareholders at the annual meeting. There is no indication, however, that they were involved in the creation of the strategy; indeed McKinsey and Northeast senior management in successive steps to completing the competitive response strategy appear to have tested it out on management groups before going to the trustees. The public record does not indicate that there was any direct input from the Board of Trustees; the trustees accepted this new vehicle for ordering the operations of the company, but they were not a driving force in either its creation or, as we shall see, its completion.

Financial Conditions at the Beginning of the New Competitive Strategy Northeast’s financial position in 1986 and 1987 was better than anticipated by its earlier annual reports. Formed in 1966 through the amalgamation of three electric companies whose histories stretched back to 1878, Northeast Utilities was the largest utility in New England and one of the twenty largest in the nation. It provided electric power to most of Connecticut, except for New Haven and Bridgeport, and to western Massachusetts

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TABLE 2.2 Northeast Utilities Consolidated Financial Performance (millions of dollars) 1986

1987

1988

1989

1990

Operating Revenues

1,824

1,878

2,079

2,473

2,616

Operating Expenses: Operation – Fuel Other Maintenance Depreciation Taxes Total Operating Expenses

429 509 158 160 329 1,548

386 562 208 192 271 1,601

416 514 191 207 342 1,748

623 630 241 198 326 2,088

678 697 238 212 336 2,236

280 169 171

277 169 215

331 191 225

385 227 203

381 213 211

2,640 2,223 4,863

2,865 2,293 5,158

2,976 2,296 5,269

2,746 2,329 5,075

2,792 2,362 5,153

Operating Income Interest Charges Income Long- and Short-Term Debt Preferred and Common Equity Total Capitalization

Source: Northeast Utilities, annual reports, various years. Notes: 1986–89 restated to exclude gas operations discontinued in 1989. Depreciation includes amortization of deferred Millstone Three return. Interest charges include borrowed funds for deferred Millstone Three return.

through its subsidiaries Connecticut Light and Power, Western Massachusetts Electric Company, and the Hartford Light Company. It had nearly one million customers (846,000 electric and 145,000 gas) and more than 6,000 employees. The company assets had a book value of approximately five billion dollars. Overall revenues and costs of operations for the second half of the 1980s, as shown in table 2.2, indicated that it was profitable. Northeast Utilities, however, operated on a slim margin of earnings, since operating income represented only 15 percent of sales and interest charges absorbed close to 60 percent of that 15 percent. The company paid out 90 percent or more of the resulting 6 percent of revenues as net income subject to dividends. Nevertheless, market conditions were favorable for increasing earnings. The mid- to late 1980s was a period of sustained growth of business activity in southern New England. The company realized gains in demand for electricity, with nearly 10 percent per annum increases in operating revenues and 5 percent increases in operating income. The first stage of implementation of the new strategy added substantially to these increases in earnings (as we indicate later).

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TABLE 2.3 Northeast Utilities Statistics on Financial Performance 1986

1987

1988

1989

1990

1.58 1.68

1.97 1.76

2.07 1.76

1.87 1.76

1.94 1.76

Book Value per Share ($) Market Price per Share ($)

16.24 241/4

16.53 201/4

16.90 197/8

16.13 221/2

16.34 20

Deferred Return on Millstone Three (% of earnings)

58.8

56.5

47.8

29.7

27.8

Earnings per Common Share ($) Dividends per Share ($)

Source: Northeast Utilities, annual reports, various years. Notes: 1986–89 restated to exclude gas operations discontinued in 1989. Depreciation includes amortization of deferred Millstone Three return. Interest charges include borrowed funds for deferred Millstone Three return.

Still, the common-share investor was not impressed by the immediate gains in earnings. The book value of assets per share remained at the $16 level over the five years from 1985 to 1990, while the market value of a common share declined from $24 to $20. Earnings per share increased by 5 percent per annum, while share price declined by 5 percent per annum. The stock price exceeded book value per share, but there was continuing concern that earnings and net income would decline; and there were reasons for such concern, given that large nuclear investments had been booked but not yet added to depreciation, holding back recovery of costs that would have justified reductions in earnings after depreciation and, ultimately, increases in rates (or prices) to consumers. Even in 1990, interest and depreciation costs equal to 28 percent of earnings, from investment in the new third reactor at Millstone Point, had yet to be included in costs for income statement and rate determination purposes (see table 2.3). As noted earlier, by the late 1980s Northeast was able to produce more power than demanded by its retail customers, and it sold the remainder into the regional power pool by contract to other utilities. As shown in table 2.4, its deficit of 2.5 billion kilowatt-hours in 1986 had turned into a surplus of 0.8 billion kilowatt-hours in 1990. This power came from its high-cost nuclear facilities. Around two-thirds of total generation came from nuclear facilities; nuclear generation had increased by one billion kilowatt hours, while non-nuclear generation did not increase, due to the new Millstone reactor coming on line. As non-nuclear generation fell with fossil plant retirements in 1990, high-cost nuclear power became a larger percentage of Northeast’s generation and was likely to be at the margin.

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TABLE 2.4 Northeast Utilities Consolidated Sales and Operations (millions of kilowatt-hours)

Nuclear Generation Non-nuclear Generation Total Generation Retail Sales, Company Use Net Purchases, Exchanges (Sales) to Other Utilities

1986

1987

1988

1989

1990

16,624 9,633 26,257 23,702

18,019 8,468 6,487 24,788

19,146 9,316 28,462 26,147

17,119 9,554 26,673 26,500

17,724 7,576 25,300 26,155

2,555

1,699

2,315

173

(855)

Source: Northeast Utilities, annual reports, various years.

In fact, the major determinant of Northeast’s financial status in the mid-1980s was the emphasis on nuclear power plant operations. The commitment to nuclear had long been less than well founded, having been based on projections of low cost of generation and high rates of growth of demands for electricity. Along with many others in the industry, Northeast had not predicted the increase in nuclear plant construction costs that it had experienced. Also, Northeast’s earlier planning had not anticipated that the relative costs of small fossil fuel generating facilities in new greenfield plants would be less than in nuclear plants, and that the fossil plants would be forthcoming in large numbers from independent (nonutility) sources. In the 1970s Northeast projected that regional electric demand would grow at 7 percent per year through the end of the century, and crude oil prices would increase to between $50 and $100 a barrel so that fossil-plant operating costs would escalate. These projections turned out to be too high by half: demand increased at less than 3 percent annually, and oil prices stabilized at $20 to $30 per barrel.18 Millstone Three began the construction phase in 1981 and was completed in 1987, in the last and most expensive wave of United States nuclear facilities (see tables 2.5 and 2.6). By the end of construction, Millstone Three costs were five times higher than those for the commercial reactors built during the early 1970s. Nuclear electric kilowatts had proved to be more expensive than any conventional fuel kilowatts.19 Northeast’s high costs of nuclear generation were not unique. Throughout the industry, nuclear plants had turned out to be more expensive to construct and operate as time progressed (see table 2.6). Enhanced safety regulations after the Three Mile Island plant partial meltdown drove up capital equipment outlays as well as operation and maintenance costs. Not only did these requirements involve additional capital outlays, they also extended construction times by years, in a pe-

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TABLE 2.5 Northeast Utility Nuclear Plant Capacity as of 1988

NU Facility

Commercial Start Date

Permanent Closing

Capacity Design Rating (MW)

Yankee Rowe CT Yankee Maine Yankee VT Yankee Millstone One Millstone Two Millstone Three

Dec 1963 Jan 1968 Dec 1972 Nov 1972 Mar 1971 Dec 1975 Nov 1986

Oct 1991 Dec 1996 Dec 1996 — Jul 1998 — —

600 582 860 550 660 875 1,156

—

—

TOTAL 1988

—

NU’s % Ownership 31.5% 44.0% 15.0% 12.0% 100.0% 100.0% 65.2% —

NU’s Capacity (MW) 189 256 129 66 660 870 754 2,924

Source: Northeast Utilities, annual reports, various years. Percent NU ownership from 1998 Annual Report, p. 34. Notes: Accounted for on equity basis; electricity committed to participants based on percentage of ownership. Nuclear generation provided 56.8 percent of NU’s 1989 total energy requirements. Holdings from 1988 do not include Northeast Utilities’ 4.06 percent holding in Seabrook, representing an investment of $190.5 million as of 12/31/88. Construction of Seabrook was complete in 1986; the NRC issued an operating license in March 1990. When Northeast completed the acquisition of PSNH in 1992, it acquired an additional 36 percent of Seabrook, 5 percent of Maine Yankee, and 5 percent of Connecticut Yankee, an additional 486.1 megawatts of nuclear power.

riod where interest rates were in the double digits, causing the costs of construction-in-progress to increase exponentially. These factors combined to create costs six times the levels expected at the beginning of construction (compare costs per kWh of the 1976–80 U.S. plants with those of the 1986–90 plants in table 2.6). A 1986 study by the Department of Energy analyzed construction costs of nuclear power plants that began construction between 1966 and 1977, with commercial operation dates extending into 1986. The analysis documented the substantial increase in real construction costs during this period, from $700 per kilowatt-hour in plants begun in 1967 to $3,100 per kilowatt-hour for those begun in 1974–75.20 It found that 75 percent of the increases could be attributed to additional outlays for labor, materials, and equipment, with 25 percent attributed to additional financing charges over the period. This study found that reactor design had became more costly, because of safety and environmental retrofits required by regulatory changes causing construction costs to escalate. Much of this increase was not accurately anticipated. At every stage of construction, utilities consistently underestimated completion costs and

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TABLE 2.6 Construction Costs of U.S. Nuclear Facilities Commercial Operation 1960–65 1966–70 1971–75 1976–80 1981–85 1986–90 Post–90

No. of Plants

Average Capacity (MW)

Average Construction Cost ($MM)

Average Cost ($/kw)

2 6 24 14 13 17 1

130 466 1,172 1,499 1,421 1,540 1,270

54.6 237.5 408.4 774.1 2,221.3 4,647.2 6,906.8

420 510 349 516 1,563 3,018 5,439

Source: FERC Form 1 data, various years. Construction costs as reported to the Federal Energy Regulatory Commission (FERC) by operating utilities in first year of commercial operation. Compiled by McGraw Hill © 1999 and published as “U.S. Nuclear Plant Capitalization and O&M Cost Database.” Total capital includes sum of land, plant structures, and equipment, and includes costs of funds used during construction.

time.21 Northeast was involved in this process, having invested in nuclear facilities over these twenty years, with Millstone Three in construction at that point in time where cost increases were the largest.

Constraints: Price and Safety Regulation Northeast’s strategic approach was developed within the framework of constraints inherent in the safety regulation of the Nuclear Regulatory Commission and the rate regulation of the Connecticut and Massachusetts utility commissions. These regulatory agencies were important determinants of the options the company had in formulating a competitive strategy. The Nuclear Regulatory Commission at that time was in the process of enhancing its safety-related engineering and training requirements for all nuclear facilities, in response to the safety issues raised by previous nuclear plant failures. It was stiffening its (license-based) requirements that allowed nuclear facilities to continue in operation. At the same time, the state rate regulatory agencies were moving toward deregulation of power generation. If this political initiative were to succeed, then outside sources had to enter markets of the franchised monopolies and offer power at prices lower than the cost-justified rates of the incumbents. The costs incurred by the incumbent before deregulation would not be recovered from responsive sales at the new low prices but would be what was

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termed “stranded.” It was not evident at that time whether, or to what extent, rate regulators would recognize the recovery of costs in previous investments by protecting the rates of the incumbent. Given its potentially uneconomic investments already in place, this was a concern for Northeast as one of many incumbents. The Nuclear Regulatory Commission had authority to determine nuclear plant operating performance, based on its responsibility for safety in operations as the plant generated electricity. As such, it knew that if changes in safety standards were to be required, they would add to costs for equipment, operations, and maintenance. Although not charged with promoting the advance of nuclear over other plant technologies, as was its predecessor the Atomic Energy Commission, the NRC had to acknowledge the financial pressures that it placed upon the companies by increasing standards. At least to some degree, it had to be mindful of imposing rules that resulted in cost levels in excess of competitive prices of power from other sources. Within the regulatory / operator community, there was not complete agreement on what was required to ensure that plants experienced safe operations while remaining competitive. The Nuclear Regulatory Commission in the mid-1980s did show confidence in Northeast’s ability to take on the new strategy while continuing to operate its nuclear reactors at a high level relative to standards. It accepted the new strategy as “business as usual” in its exchanges with the company on operational safety. From the commission’s view, at the plant inspection level, the company had a long record of safe performance at its Connecticut Yankee facility and the two older plants at the Millstone site. It expected that the third plant coming on line would sustain Northeast’s reputation as a leading nuclear plant operator. NRC inspections of Northeast plants in the mid-1980s resulted in grades for its “Assessments of Licensee Performance” at the highest or second highest level. For Millstone One, Plant Operations, Maintenance, Emergency Preparedness and Security were all level one, while only Radiological Controls, Engineering Support, and Quality Verification were at level two (i.e., “requiring some improvement”; see table 3.6 in the next chapter for a detailed listing of scores). In inspections performed later in the 1980s, during the first round of implementation of the strategy, Millstone Two was evaluated at “level one but declining” on Plant Operations and at level two on Maintenance. Millstone Three was at level two on Plant operations. Even with these declines, the three plants at this site were ranked above those of companies “in difficulty,” as was evidenced by level-three ratings elsewhere. Northeast was subject to additional federal regulation, specifically that of the interstate transmission and sale of power. Federal mandates for

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this regulation on transmission rules and on wholesale prices were implemented by the Federal Energy Regulatory Commission (FERC). By rulings and case-by-case decisions, the FERC as well as the state agencies were beginning to undertake a policy shift favoring competition in the supply of power. The industry first experienced this change in policy in the Public Utilities Regulatory Policies Act (PURPA), passed by Congress in 1978, which was designed to promote conservation and cleaner air. PURPA established that new generation sources, termed independent power producers (IPPs), could put electricity onto the grid of incumbent utilities. Although PURPA applied to industrial plants with any “thermal load,” that is, that produced heat in their industrial processes, new sources also qualified for PURPA treatment, such as those that used biomass waste products as fuel to produce electricity.22 Electric utilities were required to purchase the PURPA power at prices equal to their “avoided costs” (the costs of producing the additional power themselves). Although the act did not allow competitive entry at retail, the extent to which investors would make capital available for developing alternative power sources was a matter of substantial uncertainty. The deregulatory initiative beginning in the late 1980s centered on separation of generation from transmission, with the intended result that incumbent utilities would “wheel” power to consumers from the lowestcost generation source. Such a change eventually would have the incumbent utility distributing power owned by others at retail, with multiple suppliers using the one set of local wires. This unbundling and extension of independent power sources into the household market was not then expected to come quickly. In 1992, the Energy Policy Act mandated access to electric transmission lines to wholesale buyers and sellers. The implementation of that act led to the FERC’s Order 888 in 1996 and Order 2000 in late 1999, but few states had implemented retail competition by 2000.23 In addition to regulation of wholesale prices and service offerings by FERC, Northeast’s retail operations were regulated by the two state public utility commissions where it provided service. Both Massachusetts and Connecticut commissions controlled retail prices and determined the quality of retail service, under franchises granted to Northeast regional subsidiaries for retail distribution service. The goal of state regulation was to set prices at levels that allowed the company the opportunity to recover its investment in the plant, equipment, and operations while providing full and continuous service to the consumers in its service region. After fifty years, the resulting costs of service and rates were widely perceived to be too high, particularly in New England and California. The solution was widely regarded to be to open up these service regions to in-

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dependent, competitive companies with lower-cost technologies. That again was a political plan in the long run. Even as Northeast was developing its strategy, the Connecticut regulatory agency, the Department of Public Utility Control (DPUC), expressed disagreement with the company’s depiction of imminent market deregulation. In a February 1988 decision, the Connecticut DPUC stated that the new Northeast strategy was an overreaction to possible, but not certain, competition in electricity markets. The DPUC encouraged cost containment to hold down retail prices, but made it clear that the company’s projections of impending losses from competition left it unimpressed: The company believes that fifteen to twenty percent of its projected load (740 megawatts) could be lost to competition by 1992, which could have serious negative effects on remaining customers who would have to absorb fixed costs [in higher prices]. The largest portion of the load loss, 520 megawatts, would be attributable to self-generation. Taking the associated revenue loss and spreading it over the remaining customers, the Company projects an increase of 1.3 cents per kilowatt-hour in 1990, or thirteen percent over what otherwise would have been projected. If revenue losses could not be recovered, the load loss would result in fifty percent reduced earnings, from $330 to $165 million. The Authority recognizes these concerns but does not agree with the Company’s assessment of their extent or imminence.24

The DPUC pointed out that business customers would not undertake self-generation to the extent implied by Northeast, absent rising electric rates, and noted that the regulatory process had kept rates constant, so as to lessen the likelihood of customers doing just that. The department also took issue with the methodology in the McKinsey study that formed the basis for the company’s projections of market growth, particularly with a “very limited sample” of twenty-three interviews with customers that provided the prediction of how extensively industrial self-generation would spread. The DPUC’s position was that the McKinsey study represented an upper bound on competitive losses of market in the next five years, rather than a projection of the likely level.25 If the McKinsey (and Northeast) projections of the extent of competitive incursion into Northeast supply markets were too high, then cost-containment programs would be too extensive and could unnecessarily increase the risk to safety and continuity in plant operations. The department disagreed with Northeast’s assessment of the impact on emerging competition because of its promise to hold down prices. That promise may have been taken more as threat by Northeast. In any case, Northeast was not dissuaded from pressing its strategy by the concerns of the Department of Public Utility Control.

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Alternative Strategies: Other Electric Utilities Cope with Threats of Deregulation in the Mid-1980s Northeast Utilities was not unique among electric utilities in moving from business-as-usual to a new strategy. Across the country, utilities became involved in this process of strategy formation and they developed a number of alternative potential strategies in response. In practice, cost containment as a strategy was chosen by very few of the major utilities. As outlined in table 2.7, of fourteen major utilities, eight chose to diversify out of electricity generation, four held to business-as-usual practices, and two proposed significant product differentiation. Only two of these fourteen utilities made cost containment an element of their new strategic initiative. Diversification, the most widely adopted strategy, was a matter of degree as well as direction; how far afield from its core business the utility would move was debated more often than whether to move away at all. The other generic strategy, product differentiation, was a relatively uncommon choice; the New England Electric System and Pacific Gas and Electric made commitments to change their operation so as to be perceived as environmentally conscious “service” companies, but it is not clear whether they saw that as constituting a change at retail, where they would be subject to rate regulation. For many of the utilities, local demand conditions appear to have defined the content importance of new strategy. Certain utilities, such as those in Iowa, Michigan, and Pennsylvania, were formulating strategies to reduce prices to large industrial customers and end the residential subsidies traditionally built into utility rate structures. They provided service in areas of economic decline and sought to attract new businesses by reducing rates. Utilities that had completed the construction of nuclear facilities and moved to operational status in the early 1980s faced high-cost operations. These nuclear projects were initially undertaken after the energy crisis of the mid-1970s, when both fuel and product prices were at alltime highs and demand growth was projected at twice GDP growth. They attempted to recover part of their original investment by supplying more generated power at lower prices than was required to achieve positive returns on investment.26 Their approach to strategy was to develop exit programs as fast as possible in that part of the country. Given problems of achieving efficiency in unrelated businesses, the larger California electric utilities slowly approached diversification as their preferred strategy. Pacific Gas and Electric took a conservative position, electing limited diversification in the early 1990s; Southern California Edison ended up choosing “slow and small moves to diversify,” and

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TABLE 2.7 New Strategy Proposed by Electric Utilities 1985–90 Date

Utility

Description of Strategy

Source

4/15/86

Duke Power Company (North Carolina)

• build and operate nuclear facilities to consolidate on in-house expertise • team approach to highquality, low-cost operations

Business Wire, 4/15/86.

4/28/86

Cilcorp (Illinois)

• diversify into nonregulated businesses and financial services • cost containment on utility service

Deborah Goeken, Cilcorp, “Following Slow Road to NonUtility Diversification,” Crains Chicago Business, 4/28/86, p. 84.

6/13/86

Duquesne Light and Power (Pennsylvania)

• diversify industrial development projects and offsystem power sales • control costs so as to keep rate increases to level of inflation

Seth Lubove, “Two Rust Belt Utilities Take Opposite Paths,” Wall Street Journal, 6/13/86.

7/1/86

AZP Group (Arizona)

• diversify outside energy (acquire MeraBand, a Phoenix-based savings bank, for $440 million)

Frederick Rose, “Utilities, Flush with Cash, Enter New Fields,” Wall Street Journal, 7/1/86.

7/1/86

Pacificorp (Oregon and Washington)

• diversify into coal mining, telephone, oil and gas distribution

Ibid.

7/1/86

Florida Power and Light (Florida)

• diversify (purchased Colonial Penn insurance for $566 million, also cable TV company) • diversify: construct cogeneration plants outside traditional service territory

Ibid., and Bill Paul, “Berry’s Heresy May Yet Prove Prophecy,” Wall Street Journal, 2/17/88.

7/1/86

Wisconsin Electric Power Co. (Wisconsin)

• diversify into industrial park development and local venture capital

Rose, “Utilities Flush with Cash.”

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TABLE 2.7 (cont.) Date

Utility

Description of Strategy

Source

7/1/86

Minnesota Power and Light (Minnesota)

• diversification as 50% partner in $400 million paper mill, also investments in land, and in water/ sewage plants in Florida

Ibid.

5/18/87

Pennsylvania Power and Light (Pennsylvania)

• price competitively, using incentives to market power aggressively and eliminate off-peak demand charges

“Pennsylvania P&L Chief Stress Marketing in Midst of Growing Competition,” Electric Utility Week, 5/18/87, p. 7.

9/22/87

Consumers Power (Michigan)

• make operations cost efficient to attract new customer business • convert Midland nuclear plant to natural gas combined-cycle cogeneration facility

House Sub-committee on Energy and Power, “CMS Chairman address to Congressional Subcommittee,” PR Newswire, 9/22/87, p. 12.

11/19/90

Pacific Gas and Electric (California)

• diversify power sources: 35% of 20,000 MW generating capacity from renewables

“Planning PG&E R&D Chief Sees Company Adding 2,500 MW in Renewables by Year 2000,” Electric Utility Week, 11/19/90, p. 12.

9/28/87

Iowa Public Service (Iowa)

• diversify into regional investments and real estate and through power acquisitions outside of region

“Utility Industry Panelists Upbeat on Confronting Competitive Environment,” Electric Utility Week, 9/28/87, p. 16.

2/17/88

Dominion Resources (Virginia)

• build alternative production capacity with costs lower than nuclear • diversify into cogeneration business outside traditional service territory

Paul, “Berry’s Heresy.”

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TABLE 2.7 (cont.) Date

Utility

6/1/89

New England Electric System (NEES) (Massachusetts)

Description of Strategy • focus on utility business • maintains services as environmentally conscious firm

Source Cameron Thrall, “New England Utilities Debut Expanded Incentives for Efficient Construction,” Energy User News, 6/1/89, p. 1.

San Diego Gas and Electric chose limiting its diversification to selling software related to its utility business.27 In the interim, the alternative was either no strategy or business as usual. Some electric utilities limited their diversification to new business in closely related fields. Even then, there were regulatory restrictions hindering that strategy. The Public Utility Holding Company Act (PUHCA) of 1935 restricted utility holding companies from owning plants in closely related activities; diversification by any one generating company into the cogeneration business was limited, for example. Dominion Resources of Virginia, however, led the way in testing those limits in the late 1970s and early 1980s by investing $90 million to acquire a half interest in the building of cogeneration facilities—an Enron Company project. Florida Power and Light and Atlantic Energy Company took that approach as well, participating in, or planning, joint ventures in other service territories in cogeneration.28 But the generic strategy of diversification, moving out of power production, was attractive generally. The extreme case was the AZP Group, which, when faced with prospective favorable growth in demand within its utility service territory, still took the position that investment was not attractive, given future wholesale competition in generated power. Its strategy did not aim at cost containment, but instead took cash from power operations to make alternative investments. Indeed, as Howard P. Allen, chairman and CEO of Southern California Edison noted in an interview, “diversification is ‘stylish.’”29 But John Sawhill, the McKinsey consultant who advised Northeast, noted in the same article, “The real question is, will the utilities stick close to their knitting or will they go into a wide range of businesses. . . . Our view is that utilities will be better off if they stay in businesses closer to home.” He also discussed a McKinsey study of fifty-eight utility corporate acquisitions outside their industry between 1975 and 1985, which found that only six were successful, with the rest split equally between clear failures and indetermi-

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nate results.30 Tension existed in strategy formulation between cost containment and diversification, but at that point diversification dominated the new strategies of the utilities.

Comparative Nuclear Strategies: Pacific Gas and Electric A perspective on Northeast’s choice of strategy and its impact on its nuclear facilities comes from a comparison with the strategy formulated by Pacific Gas and Electric (PG&E) and how that affected its two Diablo Canyon nuclear plants that became operational in 1985 and 1986. These two nuclear plants on the California coast were similar in size and technology to Millstone Three. In addition to high construction costs, a phenomenon common to nuclear facilities at that time, Diablo Canyon faced exceptional construction problems, including the late discovery of an offshore earthquake fault and mistakes in building that required extensive reconstruction. As a result of the California Public Utilities Commission’s review of construction costs of these plants, PG&E, the commission, and major litigants entered into a long-term pricing settlement as an alternative to traditional cost-of-service pricing. Diablo kilowatthours would enter the grid based on a preestablished price schedule that avoided a specific calculation of the “reasonableness” of the $5.8 billion of construction costs included on the company’s books as plant in service. Given the assumptions during the settlement process, the price in practice allowed substantial room for a profit margin on sales (i.e., pricemarginal-cost differences). Within certain broad parameters, and because of the agreed-upon margins, revenues from sales that exceeded expectations effectively recovered the original investment of the facility in produced electricity over its lifetime.31 Because the settlement removed Diablo Canyon from traditional regulatory price review, PG&E operated the two plants as a “business unit,” separate from other electric generation. Maintenance and operations costs as well as additional capital investment were evaluated on whether they kept the plant operating at full capacity (i.e., minimizing “hazard” and maximizing revenues). Targets were set for spending with the sole goal of enhancing long-term plant generating rates.32 PG&E’s corporate goals for 1989, immediately following the settlement, included “operat[ing] the Diablo Canyon Nuclear Power Plant at the highest level of safety, reliability, and performance.” Cost control was included under secondary Financial Strategies, and the wording qualified cost containment as “consistent with achievement of safety and performance goals.” The focus at Diablo Canyon was “invest[ment] in enhancements to safety and operating reliability,” and “minimizing time

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for outages or derated status.” To do this, the plants must “comply with all safety and regulatory requirements, maintaining high levels of confidence and credibility with the public, regulatory agencies, nuclear industry associations and the Independent Safety Committee.” The nuclear business unit centered all aspects of operations: “increase awareness of and commitment to performance-based operations.”33 This strategy was the opposite of the Northeast strategy, which took risks with plant operating rates in order to take deep cuts in current maintenance expenses.

The Northeast Competitive Strategy in Context—Was It at Inception the Dominant Strategy? Northeast Utilities’ approach to formulating new corporate strategy was not different from that of other utilities, or other corporations for that matter, and its choice can be examined in the same way we would examine that of other companies. It was an evident competitive strategy, which in the context of corporate decision-making consists of a collection of plans and programs that seek to determine an exact company position with respect to competitors and customers. Michael Porter, the eminent scholar of strategy, described the process as “developing a broad formula of how a business is going to compete, what its goals should be, and what policies are necessary to carry out that goal.” In this context three generic approaches were available as alternatives to power companies in the 1980s: (1) a focus strategy, reducing activities to those in the core of managerial competency and in the strong technologies of the organization; (2) a differentiation strategy, creating services or products distinct from those of competitors, so that consumers associated unique characteristics with those offerings; (3) low-cost dominance, reducing costs below those of other firms that provide the same product, so as to undertake pricing initiatives that take away market share.34 The third, low-cost dominance, was most central to Northeast’s strategic approach. As the 1988 Annual Report noted, “No matter what moves we might contemplate, none will succeed unless we continue to operate our core electric business as efficiently as possible.”35 In Northeast’s view, reducing costs in electric generation was necessary to achieve price levels that sustained its market share against the coming competitive entrant or the industrial customer undertaking self-generation. Management’s extension of cost containment to all aspects of its business in the budget process took it beyond just a program for current operational effectiveness to a make-over of the entire company. As Porter pointed out, operational effectiveness is not competitive strategy and, while a component of an organization’s success, it is not sufficient for de-

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veloping an advantage in a competitive market.36 Northeast went beyond seeking efficiency gains to operating at lower levels of cost in all its production systems. In evaluating this corporate initiative, two questions can be asked: Was the strategy the most effective response to changes in its markets? Could the strategy achieve its goals with the proposed implementation program? Conceptually, cost dominance was potentially operational, but it need not have been the most effective strategy. Northeast Utilities’ mid1980’s outlook was such that cost dominance would prevent the loss of a significant percentage of generation load to competitive entrants, when competitive entry was to occur, whether in the next decade or ever. But in the interim, it had the potential of increasing profit (earnings) beyond what was expected in the then-current rate regulation process.37 Even more important, the containment strategy was by its nature subject to top / down implementation. It had to work by means of operations, maintenance, and capital expenditure targets set in budgets specified by high-level committees before being sent to operating units. No operating unit would cut its own maintenance outlays relative to other units. To this top-down process was added a feedback process at the bottom of the organization, as to the safety and reliability of operations, from the employees on the plant floor or, finally, from plant interruptions and forced outage. Cuts in maintenance in an executive budget session, for example, created potential risks in operations that would be realized not there but on the plant floor at some later date. The cost structure in nuclear facilities was determined by large frontend capital investments and fixed outlays for fuel, so that the costs to attack in order to achieve containment were in operations and maintenance. This is not to imply that management did not have to deal with regulation of safety. Northeast Utilities’ ability to continue running its nuclear facilities required ongoing approval of the Nuclear Regulatory Commission, an agency concerned about forced outages and skeptical about long lists of safety violations in plant operations. Any attempt to reduce costs had to be made with awareness of potential degradation of plant conditions that could result in the commission calling for the shutdown of the Millstone facilities. This concern appeared to be manageable to strategists at Northeast Utilities. The process of putting new nuclear facilities on line in the mid-1980s had been successful, given that company generally had high nuclear-plant safety ratings. This record led management to believe that it could maintain a working relationship with the regulator while pursuing cost containment as a priority. Also, in spite of its risks, cost containment had the potential of striking a responsive chord with state regulators in Connecticut and Massachusetts, who had exerted pressure to hold down prices, as evidenced in rate decisions

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29

in both states, and who had supported efforts to control costs by making it easier to reduce prices in industrial markets where self-generation was competitive, while minimizing politically unpopular increases in residential service prices.38 But both state agencies were to warn Northeast that their acquiescence to cost containment was not in agreement with cuts in engineering, design, safety support, and analyses of performance in the nuclear plants. They did not support lower costs at the risk of lower levels of plant safety at Millstone. Given all this, in comparison to the strategy of other utilities, the Northeast Utility commitment to cost containment was conceptually problematic from the start. Other strategies, centering on exit from highcost operations, would have cut back nuclear power production. This alternative, adopted by other utilities, had impressive credibility, particularly if the deregulatory process were to take more than five years, since it would allow substantial recovery of stranded costs of utility nuclear investments in higher allowed rates in the interim. Even though creating a competitive strategy within a traditional utility could be a formidable task and take time, Northeast’s strategy involved more restructuring and cost cutting than one might expect for a utility in “threatening” but not yet “actual” competitive markets. The conceptual logic in the Northeast strategy was present but not compelling, in part because it did not have a factual foundation in deregulated market conditions The strategic choice made by Northeast Utilities would have been convincing, even if as an extreme response, had it been a response to immediate competitive entry and immediate changed policies of its regulatory agencies. It had to be driven by the imperative of near-term loss of markets to competitors in order to justify deep immersion in low-cost dominance. Although searching for cost efficiencies in operations over time could prepare a utility for a new approach, deep cost reductions would be difficult to justify without an imperative, given the potential for problems in sustained operations in nuclear plants. But the strategy could achieve low-cost dominance only as long as it did not destroy plant operational performance in the long run. That would destroy its working relationship with its regulators and bring about recognition of the costcontainment / hazard trade-offs taken to the extreme in its competitive response strategy. At the extreme, as costs are cut 13 percent in engineering, maintenance, and training, then hazard rates at Millstone would increase. There is no discussion of hazards in Northeast’s evaluation of the strategy. McKinsey provided a warning on the phenomenon, but the potential return / risk trade-off of the strategy was not made explicit in company presentations.39 But implementation had to prevent the NRC and state agencies from forestalling Northeast’s cost containment because of risks of regulatory plant outage. As we shall see in our narrative

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of the events that followed, that requirement proved impossible to achieve. Then why would management, with the Board of Trustees, adopt this most forced of competitive strategies? The obvious response is that it was the most financially attractive in the first years of its results. The “vision” of leadership in a competitive New England power market was, as depicted by McKinsey, more than attractive. The financial economics of utility regulation added to the short-term attractiveness, because every dollar of cost savings went to the bottom line (with fixed regulated prices), an addition to the level set in rates to recover the cost of capital. Any dollar of increased earnings was potentially the first dollar of profit in excess of the amount necessary for competitive returns to equity, that is, the first dollar of “excess” profit. The new strategy offered the opportunity to achieve that higher profit in the then-current year’s revenues. It is possible to conceive of those gains in the first year of the new strategy. Based on 1986 actual results, implementation of the 12 percent cost-reduction program would release $80 million of free cash flow (based on $667 million of operations and maintenance outlays, as indicated in table 2.2); after taxes at the average rate, the addition of $36 million would constitute a 21.4 percent increase in net income. In the context of the “hazard / return” framework, this gain must conceptually override the longer-term increase in risk; that is, the target cost cuts would add one-fifth of net income without adding to the risk of forced downtime in the nuclear plants that year. The order of magnitude of percentage income gains from the initial stage of low-cost dominance strategy was twice that of percentage reductions in operations costs, no matter the long run ramifications of these aggressive reductions on future plant operations.

Three The Nuclear Power Context for the New Competitive Strategy

Northeast in 1986–91 went into the first phase of its competitive response strategy, by establishing and implementing low-cost dominance throughout the company. This required it to find cost savings in both fossil and nuclear generation, the two predominant power sources. Taking cost savings in nuclear operations was more complex than in fossil generation, since cost savings in nuclear created tension between the company’s financial performance and the safety-regulation process surrounding nuclear power. The practical issue was how to operate plants at cost levels comparable with those of fossil plants and still make the outlays required to meet NRC standards for licensed accident avoidance. Northeast took an obvious, direct approach to resolving this issue. To contain costs in its nuclear facilities it focused on non-fuel operating and maintenance expenses as the controllable part of total expenditures. Nuclear fuel costs were not a possible source of cost savings, given that fuel use was proportional to power generation and prices for fuel rods were set in markets in which Northeast was only one of many participants. Nonfuel operations and maintenance outlays had to be the target for large cost-savings. Northeast’s nuclear facilities required expenditures on departments focused on engineering, analysis, regulatory compliance, and scheduled maintenance—each in the range of $50 to $150 million per annum—all expenditures unrelated to day-to-day power generation. These outlays became the targets of the cost-containment strategy.

The Complexity of Nuclear Power Systems A broadly based survey of nuclear-plant operating characteristics is necessary to make this approach to cost cutting appear more than simplistic. Nuclear power is the most complex technology now in use for commercial electricity generation. The technology used in conventional fossilfuel electric generation has been in place, with refinements, since the early twentieth century. Nuclear generation was developed more recently and more quickly. Commercial nuclear generation of electricity began in the 1950s and, over a relatively short period following the 1954 Atomic

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Energy Act (AEA), a transfer took place from government demonstration plants to private commercial generation in nuclear facilities. The Atomic Energy Commission, set up by the AEA, had as its mission to encourage peaceful applications of atomic energy, particularly power generation. Shippingport, the first large-scale commercial operation, came on line in Pittsburgh in 1957, Dresden in Illinois was constructed without government funding in 1959, and construction on Oyster Creek, the first plant constructed on purely economic terms, that is, without either government or corporate subsidy, was completed in 1969 by Jersey Central Power and Light Company. With long construction times, most nuclear plants came on line over the next twenty years, surpassing natural gas in 1983 and hydroelectric generation in 1984, becoming second only to coal-fired plants in total plant capacity. By 1989, the number of operational domestic nuclear facilities reached its maximum of 110 plants.1 There was never any systematic standardization of nuclear plant design over this period. The technology of nuclear generation evolved plant by plant. In early designs coolant passed directly through the core to a heat-exchange system; older plant operating systems were renovated, and newer plants were designed with advances in coolant system technologies, in which coolant passed heat to a secondary exchange system. The size of plants increased, exceeding that of other generation facilities, to gain cost savings from scale (although, contrary to expectations, cost savings due to scale turned out to be difficult to realize as safety requirements became more stringent).2 Given long construction times and evolving design, lack of standardization resulted in each plant becoming a unique prototype. A summary of this phenomenon was provided by Constance Perin: The technology of a nuclear plant is much more complex than that of other conventional energy sources, particularly when compared to fossil fuel plants. Although both use a fuel source to produce steam heat that is converted to electric energy, a fossil fuel plant is relatively simple to operate. Nuclear operates on a larger scale. A nuclear reactor requires 200 to 1,000 people, and during refueling the number of workers can increase by a third or more. It has thousands of valves, miles of internal cables, and hundreds of sensors. The number of work activities planned and implemented annually can range from several hundred to several thousand.3

If continuous operations that produce electricity at planned or “design” levels are to be sustained, then radiation controls, plant chemistry, coolant systems, and security systems have to conform to design. That was the intent of “design.” Component failure in operations, or in refuelings, can lead to severe radiation and steam accidents that endanger employees as well as the surrounding community. Monitoring and con-

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trolling these operating conditions, so that they do conform, requires continuous plant maintenance. This process is time consuming and is centered on work done to repair and update systems during scheduled outages when reactor fuel rods are replaced. Cooling the reactor core before repairs, refueling, and then returning the reactor to the necessary power levels can take weeks. Component failure in that process can lead to severe widespread radiation and steam accidents.4 Controlling radiation has priority—from the time that commercial operations begin, the design, construction, and operating procedures of nuclear plants incorporate systems to achieve what is termed the “practical impossibility” of nuclear fuel meltdown, ensuring no release of radiation. Since no one system can be completely fail-proof, however, the designs include multiple systems for the same task, which are expected to provide a “practical” approximation of radiation-release-free conditions, since they are unlikely all to fail simultaneously. That is, the independence of key variables causing failure in separate systems makes the probability that all will fail at the same time low enough to produce a solution termed “radiation-free plant performance.” But this term is still based on subjective judgment as to how a design will work, as indicated in a standard treatise on nuclear plant operations: Designing a safe nuclear plant or maintaining the safety margin of an operating plant which is statically sound requires an effective understanding of the dynamics of the reactor and its associated components and equipment. Such an understanding is necessary in order to ensure that the constraints imposed either by the materials of the plant components or by the environment in which the plant operates, will not be exceeded at any time. The first step is to select a set of variables, the state variables, that are adequate to characterize the physical processes taking place during the operation of the system. Typical nuclear plant state variables are the neutron density, the coolant temperature, the control rod position, etc. The second step in the process of understanding reactor dynamics is to find the time-dependent equations that interrelate the different variables. The third step is to solve the dynamic equations either analytically or with a computer. . . . Even for relatively simple systems, the establishment of general solutions is practically impossible.5

What has been “practical” in maintaining a safe condition has turned out to be the construction of facilities with overlapping systems that shut down when temperatures and pressures exceed levels sufficient to produce turbine electricity, which will then prevent temperatures reaching levels leading to the melting of the nuclear fuel rods. This approach, characterized as “defense in depth,” is implemented by setting limits in design before plants are built. If the equipment then fails, the reactor then shuts down on command or automatically (in a “forced

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outage”). The design contains sufficient operable independent and redundant systems made up of equipment with low failure rates so that an accidental stopping of the coolant flow from the nuclear core takes place only with an extremely low probability. As noted as early as the 1960s, “Reactors have been ‘docile’ even when purposely or accidentally mistreated. Experience has shown that reactors are more stable and reliable than anyone had a right to hope or believe in the earlier days, the treatment according to design in operations with continuous maintenance should result in continuous kWh.”6 Although reliance on multiple and automatic shutdown systems was shaken by the Three Mile Island nuclear accident in 1979, the “according to design” approach was never abandoned. More sophisticated shutdown technologies and new methods for keeping systems independent have enhanced redundancy. A nuclear industry group described this for newer reactors: The plant has built-in sensors to watch temperature, pressure, water level and other indicators that are important to safety. These sensors are linked to control systems that adjust or shut down the plant—immediately and automatically—at the first sign of trouble. These safety mechanisms operate independently, and each has one or more backups: If one set fails, another is available for safe shutdown of the reactor.7

The added automation of these safety systems made newer nuclear plants expensive, but the accident at Three Mile Island was a turning point in making the case for such additional outlays. There was no catastrophic single failure of equipment, such as a large pipe break, at Three Mile Island, as had previously been the major concern of the industry and regulators. Instead, a combination of relatively minor mechanical failures compounded by operator error brought that plant down. The accident made clear that the mechanical failures could result from any of the thousands of small parts subject to current corrosion or breakage.8 The new safety systems had to keep track of the smaller piping and electrical systems. In addition to changes related to the new safety systems, nuclear facilities in general during the 1980s developed a systemic corrosion problem, which contributed to an escalation of nuclear maintenance costs nationwide. In 1988, 1991, and again in 1995, industry-wide studies of costs in nuclear power found that inflation-adjusted operating and maintenance expenses were increasing 12 percent annually. There was a 17 percent annual increase in capital costs over the same period. These maintenance and capital cost-increases contributed to a new-found realization that there was an ongoing cost increase problem with nuclear power.9 Outlays for support activities central to the safety of nuclear plant op-

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erations increased. Approximately 67 percent of total operating and maintenance costs in nuclear were labor costs, with the remaining 23 percent used for materials and supplies. Only 16 percent of plant staff perform the duties of operators, while the rest are classified as safety related: 47 percent perform support activities central to engineering and safety, 17 percent provide security, with most of the remaining 20 percent performing various administrative and managerial tasks.10 Nuclear power technology can be characterized as front-end loaded on labor costs that do not figure directly in operations.

Safety Regulation at the Nuclear Regulatory Commission By the last half of the 1980s, the Nuclear Regulatory Commission was setting detailed specifications for required operating procedures, particularly for maintenance in ongoing facilities. It estimated in 1985 that over 35 percent of “abnormal occurrences” in plants during the prior ten years were related to maintenance deficiencies; not only was there not replacement of worn or outdated equipment, but “human error” had been allowed to occur in procedures that had resulted in incorrect installation of equipment. In spite of steps taken to improve maintenance programs, the commission insisted that licensees still “had a long way to go” and sought to make maintenance a matter of “HIGHEST priority.”11 The changes that the Nuclear Regulatory Commission was putting in place in the late 1980s to increase safety were outlined in the testimony of Roger Mattson, the Northeast Utilities witness in a Connecticut DPUC review, which occurred in 1997, after the shutdown of the Millstone plants. His testimony listed a series of increasingly stringent requirements, quoted below: •

Motor-Operated Valve Performance: In 1989 NRC staff issued “Generic Letter 89-10,” requesting the industry [i.e., requiring operators] to “verify the design-basis capability” of motor-operated valves controlling the flow of cooling water [i.e., coolant in the system]. Over the next few years, weaknesses were found in these valves in several areas. (See NRC Information Notice 96-48, “Motor-Operated Valve Performance Issues.”) • Management of Construction, Design, and Operations: In May 1984 the NRC staff issued NUREG-1055: “Improving Quality and the Assurance of Quality in the Design and Construction of Nuclear Power Plants.” This report considered both construction faults and poor management as major contributors to system breakdown. • Operator Training: The Commission issued a proposed rulemaking in November 1984 and a Policy Statement in March 1985 to improve [i.e., re-

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quiring improvements in] the training of plant operators. A final rule was issued in March 1987, “Operators’ Licenses and Conforming Amendments” (FR 87-6478), that rule imposed additional training requirements in a series of generic letters to plant operators. Increased Maintenance: . . . In response to a plant failure in Salem, Massachusetts, the NRC increased inspections [in 1983] in all plants to increase licensee attention to maintenance programs. After finding “significant improvements,” the NRC also issued a policy statement in 1988 that described characteristics of an adequate [i.e., improved] maintenance program. In addition, the NRC issued a Proposed Rule on Maintenance later in 1988 that required plants to develop and implement specified programs. Then the NRC also initiated special inspections and a draft regulatory guideline in August of 1989, to aid in interpretation and implementation of the final maintenance rule. The NRC issued a Revised Policy Statement on Maintenance in 1989, which recognized industry improvements and suspended final rulemaking for eighteen months. At that point [in 1990] the internal industry group focused on safety, the Institute of Nuclear Power Operators, (INPO) issued an industry maintenance standard, and in 1991 the Commission issued a final maintenance rule essentially adopting the INPO rules.12

These extensions of NRC oversight into the maintenance area added up to increased regulatory involvement in plant operations. Standards for maintenance were made more rigorous and maintenance practices were to be more completely documented, with required feedback into safety analysis. The commission instituted a new “safety assessment scale” to summarize the results from its inspections and reports, as well as the “Systematic Assessment of License Performance” (SALP) program, described by the commission as providing “a retrospective view of the relative overall strengths and weaknesses of a licensee’s performance [intended] to identify common themes or symptoms.” SALP ratings were intended to assist in determining changes in quality of plant safety over time. Every eighteen months each plant had a SALP review, with summary grades based on the commission staff’s assessment of the reports and inspections made during the period. If the scores fell, then the number of inspections increased, and if they fell to levels indicating inadequacy, the plant was then placed on the “Watch List.”13 The scheduled meetings of NRC senior management and commissioners centered on the plants identified as “Watch List” plants, since they had been determined by staff to have the highest probability of potential unsafe operations. Plants on the Watch List were graded in three levels: (one) those plants with improving performance that were candidates to be taken off the list; (two) those allowed to continue operating but requiring a high degree of

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NRC scrutiny; and (three) those required to be shut down with restart requiring an explicit vote of the commissioners.14 This process made clear that the NRC was imposing costly new requirements on operations in the middle-to-late 1980s.

Self-Regulation in the Nuclear Industry Analyses of price and entry regulation of utilities have, as a rule, found that companies undertook activities that were required by regulation and that surveillance encouraged them to “do the right thing.” Still, there are a number of alternative models that have proved applicable to the relationship between regulator and regulated entity. R. A. Kagan and others describe a number of ways that relationships can be categorized: regulators as “policers” while corporations calculate the benefits and costs of evasion; regulators as leaders that convince those being regulated that complying with regulations is “the right thing”; regulators as consultants to corporations seeking on their own to do “the right thing.”15 None of these models implies that all participants in a regulated industry would operate in ways that comply with or exceed regulatory safety standards in hazardous operations. More specifically, one study detailing the effectiveness of nuclear safety rules focused on noncompliance, based on the assumption that companies violate regulations unless they are likely to be caught and penalized. This model did not allow for the possibility that managements of nuclear facilities would choose to do better than meet the standards.16 Another model assumes that “the amount of risk acceptable to the nuclear firm is likely to be greater than the amount acceptable to society.”17 It cites three reasons why nuclear firms are not motivated to be as safe as (societal) efficiency requires: (1) corporations can lose no more than their net worth; (2) part of the risk, that is, to future generations, is not adequately represented; and (3) by statute the liability of nuclear firms for accident damages is limited.18 In contrast is the LaPorte-Thomas model of nuclear regulation. It points to findings that “nuclear power plants are quite diverse in management style and are sometimes proactive in complying with Nuclear Regulatory Commission regulations.” Their study of the Diablo Canyon nuclear facilities in California describes operations that exceed safety ratings by undertaking operations and maintenance expenditures beyond what is consistent with compliance standards.19 An extension of LaPorte’s approach can be found in the strategy of the Institute of Nuclear Power Operations (INPO). INPO can be seen as an industry-wide effort to enhance performance beyond that which is

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strictly consistent with regulatory compliance and, thus, the implied regulatory level of safety for plant operations. Unlike most trade groups, which act to protect their constituents from regulation, INPO has taken on the role of super-regulator, attempting to define safe operations more rigorously than the NRC and to require management’s voluntary compliance with these higher standards across the industry.20 Developed as an industry response to Three Mile Island, INPO exerts pressure on nuclear operators by doing its own inspections, parallel to those of the Nuclear Regulatory Commission, issuing more rigorous plant performance grades, and then working with corporate executives to encourage improvements to attain the higher level of grades, in both operating practices and management. INPO ranks nuclear facilities and presents its findings to the CEOs of the companies in meetings closed to the public. It uses pressure, described as “peer humiliation,” to impress upon management the importance of higher-level safety in operations found in other plants, to break down the insularity of companies and encourage the sharing of expertise.21 The Nuclear Regulatory Commission has endorsed INPO’s quasiregulatory role. It has often accepted INPO’s evaluations as complementary to its own and has put into place INPO standards in many areas. For example, in 1985 the Nuclear Regulatory Commission published a policy statement “embracing INPO rules” on operator training. Litigation brought by a public interest group had required the NRC to develop its own training standards, and the commission in effect then codified INPO’s practice.22 Even so, in various ways INPO’s practices have been at odds with NRC regulation. INPO operates in secrecy, with its reports unavailable to the public, even when they are made available to the Nuclear Regulatory Commission, which is bound generally to make public notice and disclosure.23 In addition, as a private organization, INPO has no enforcement mechanism and cannot ensure that its proposals for increased safety are effectively realized.

Safety Culture and “Management Style” Inherent in all Nuclear Regulatory Commission regulations and requirements, as well as in INPO reviews, is the recognition that management determines the safety of plant operations. The commission has made it clear in numerous statements that compliance with its rankings, while necessary, was not sufficient and that corporate management had to encourage and create an atmosphere promoting safety beyond the “regulatory margin.”

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The commission at several points described the process of achieving a corporate attitude emphasizing safe operations, that is, developing “a safety culture.” Thomas Murley, the NRC Director of the Office of Nuclear Reactor Regulation, spelled this out in 1989 in a speech to the industry and repeated this position on numerous occasions. He described a “true safety culture” as having the following general characteristics: • • • • • •

insistence on safety and quality by the top management of the company a disciplined approach to all operating activities strong engineering support for operations insistence on sound technical bases for actions rigorous self-assessment of performance insistence on strict accountability24

He summed up the position of the NRC and plant operator as follows: “The NRC cannot mandate a safety culture at a plant, nor can it develop one where it does not exist. Our role is to point out standards for excellence in operating nuclear plants and to evaluate licensee performance against those standards.”25 Murley noted that plant safety is defined in answering two questions: How safe are systems designs? Can operating procedures, when replicated, generate consistently safe results? In the first, his position was that probabilistic risk assessment, which was intended to assess the safety of plant designs, was of little help in determining whether plants are operated safely. Instead, for an effective assessment of operational safety, he “placed heavy emphasis on the SALP process.”26 He listed key indicators of licensee performance with respect to the second question: (1) commitment of senior management attention and financial support to safe and efficient operations, including “detailed indicators” of management and board of directors’ awareness, involvement, and attitude; (2) evidence of clear lines of authority, depth of engineering support, and technical competency in plant management; (3) effective communication of the results of onsite safety reviews; and (4) adherence to design-based standards in actual plant operations.27 The Nuclear Regulatory Commission made its concern explicit as to the adequacy of management systems in its statement entitled “Conduct of Nuclear Power Plant Operations,” issued in January 1989.28 The statement noted that management at each reactor facility must establish and maintain a professional work environment with a focus on safety in control rooms and throughout the plant. The commission stated that those licensed by the NRC to operate the nuclear reactor had to be “keenly aware” of the “special trust” conferred through the license, and that the licensee’s first responsibility was to assure that the reactor was in a safe condition at all times.29 The Nuclear Regulatory Commission noted further,

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The working environment provided for the conduct of operations at nuclear power facilities has a direct relationship to safety. Management has a duty and obligation to foster the development of a “safety culture” at each facility and to provide a professional working environment in the control room and throughout the facility that assures safe operations. Management must provide the leadership that nurtures and perpetuates the safety culture. The phrase “safety culture,” refers to a very general matter, the personal dedication and accountability of all individuals engaged in any activity which has a bearing on the safety of nuclear power plants. The starting point for the necessary full attention to safety matters is with the senior management of all organizations concerned. Policies are established and implemented which ensure correct practices, with the recognition that their importance lies not just in the practices themselves but also in the environment of safety consciousness which they create.30

The statement specifies detailed requirements for ensuring this control room environment. But, even given the extent of detail in this regulatory exercise, the commission’s overall priority was that the corporation itself develop its own safe practices in operations.31 Operators of nuclear facilities were expected to self-regulate in a manner that met the agency’s standards. An illustration of this process, to incorporate regulation with an internal “safety culture,” is shown in figure 3.1. Prepared for an internal Northeast workshop on quality assessment by W. R. Corcoran, a consultant specializing in nuclear plant operational quality, the figure demonstrates how regulation and self-assessment all lead to corrective action in operations.32 Power station operations produce unexpected “events,” such as a coolant system malfunction leading to a shutdown. The “event” leads to plant-operator-initiated causal factor analysis, with conclusions and recommendations to go to management for review and decision; management orders corrective actions to be undertaken that, when effective, feed back into power-station stable operations (that is, an absence of repeat “events”). Alternatively, without an “event,” either NRC inspection or self-assessment can trigger discovery of problems (“improvement opportunities”), which lead to causal factor analysis and effective corrective action. In this view, causal analysis and effective corrective action are the keys to nuclear operations that meet safety requirements. Incorporation of a safety culture of this level adds substantial additional dollar outlays on operations and maintenance. Safety-related programs in “self-assessment” can break budgetary targets, and they are antithetical to top-down budget-setting goals for reducing maintenance outages.

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EVENTS NRC INSPECTION RESULTS INDEPENDENT SELF ASSESSMENT

LINE SELF-ASSESSMENT

SUBSTANTIVE PROBLEMS

SELF-ASSESSMENT DEFICIENCIES

IMPROVEMENT OPPORTUNITIES

NUCLEAR POWER STATION CAUSAL FACTOR ANALYSIS

CORRECTIVE ACTION PROCESSES

MANAGEMENT REVIEW AND DECISION

Figure 3.1. The Nuclear Station Learning Process. Source: William R. Corcoran for NU, “A Vision of Quality: A Workshop on SelfAssessment, Event Analysis and Continuous Quality Improvement,” 1994, Connecticut DPUC Docket 96-10-060, Responses to Interrogatories, Box 78508081. Used with permission of William R. Corcoran.

Cost Containment in the Context of Safety Regulation Northeast adopted a low-cost dominance strategy as a competitive response to the changes it expected in future markets. This strategy required the company to observe budget targets, by cost cutting aimed directly at plant operations support. The use of self-assessment and causal factor analysis, central to the feedback process illustrated in figure 3.1, was in conflict with the implementation of the strategy. The cost containment goals set by Northeast Utilities in the mid-1980s were extremely ambitious. In addition, Northeast had three problem areas that exacerbated this conflict. First, its newest and largest nuclear plant had turned out to be extremely expensive, with extensive cost overruns putting pressure on the company’s ability to recover this investment from kWh sales at current regulated prices. Second, ongoing changes in plant design nationwide were reflected in Northeast’s facilities of differing vintage, size, and design, which created a new level of complexity and costs. Table 3.1 indicates the substantial design variations in Northeast’s three facilities at the Millstone site. Although a common location could lead to savings in functions such as security and transport, design differences meant that there were few common technical elements to provide potential gains

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TABLE 3.1 The Millstone Nuclear Plants Millstone One

Millstone Two

Millstone Three

Design Rating in Megawatts

660 MW

870 MW

1,150 MW

Start of Commercial Operation

March 1971

December 1975

November 1986

Number of Fuel Assemblies

580

217

193

Weight of Uranium Fuel

120 tons

96 tons

111 tons

Reactor Type

Boiling water

Pressurized water

Pressurized water

Reactor Manufacturer

General Electric Company

Combustion Engineering Inc.

Westinghouse Company

Engineer/Constructor

Ebasco Services Inc.

Bechtel Corporation Engineering

Stone & Webster Corporation

Approximate Cost of Construction

$200 million

$600 million

$3.8 billion

Source: NU website http://www.nu.com/aboutNU/power/mill.htm, accessed August 24, 2000; Energy Information Administration, website: http://www.eia.doe.gov/cneaf/nuclear/ page/at a glance/reactors/nuke13.html, accessed August 24, 2000. Construction costs in nominal dollars.

from applying operational learning on one reactor to another. Third, Northeast’s cost containment centered on infrastructure, such as engineering and maintenance support, and, given the facilities’ design variations, opportunities for savings by sharing technology across nuclear facilities were limited. These problems facing implementation of the strategy did not deter Northeast from proceeding on an extensive program to contain nuclear operating costs at Millstone. The challenges that arose in implementation were revealed in proceedings before the Connecticut Department of Public Utility Control: the decision in a rate case filed in 1987 by Northeast’s retail utility Connecticut Light and Power (CL&P) stated, “The major theme . . . [was] the need to address competition from selfgeneration and its solution of cost containment and rate design changes

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to reduce the cost of electricity to those customers most likely to generate electricity themselves.” The commission’s response to Northeast’s view of the future was the same as earlier—“the competitive threat is not as imminent as CL&P suggests.” It did agree, however, that “the company has much work to do in further cost containment,” but noted the “need for improvement of reliability” to ensure that plants remain on the system.33 The DPUC decision reviewed the company’s strategy of cost containment as presented in the initial filing: The company indicates its intent to adopt a significant cost reduction program in response to price competition. It emphasizes measures to reduce nonfuel operating and maintenance expenses by 1990 to levels considerably lower than the amounts spent in 1987. The company’s data indicate that a target revenue requirement reduction of $294,000,000 would be needed by 1990 on an NU system basis for the company to remain competitive, including $66,000,000 for lower fuel and purchase power costs, $108,000,000 for capital related costs, and $120,000,000 for non-fuel O&M costs.34

The commission accepted the estimates of CL&P for reduced levels of costs at Millstone One and Two for plant maintenance.35 The Connecticut regulator subsequently noted, in response to a CL&P filing made the following year, that the company was “in the midst of a cost reduction program in response to price competition.”36 Although the company did not explicitly quantify cost savings in its application, the decision cites evidence of savings in several areas, including reductions in full-time employees and nuclear engineering contractor services. The company indicated that non-fuel operation and maintenance expenses, specific plant outage expenses, and storm restoration costs for the first six months of 1988 were approximately 1 percent higher than those expenses for the same period in 1987. The DPUC decision presented Northeast’s expected spending for company-wide operations and maintenance: Northeast expected to reduce operating and maintenance expenses by 6 to 9 percent over two years. These reductions referenced in the decision are shown in table 3.2.37 The company’s next CL&P rate case filing presented a sample of nuclear plant expense accounts that compared 1987 total nuclear plant expenses for the Millstone facilities attributable only to CL&P with those expected in 1989.38 In this filing, the cost reductions, as shown in table 3.3, were $5.6 million by 1989 out of $35.7 million of base year 1987 costs. The decision held that test year nuclear expenses (i.e., other than for plant outages) would serve for ratemaking purposes, with savings on that amount to be split 50-50 between ratepayers and shareholders. Only a portion of total Northeast nuclear expenses were attributed to CL&P operations; the total savings the company expected to have in

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TABLE 3.2 Northeast Utilities’ Estimates of Functional O&M Savings under Its Competitive Response Strategy (millions of dollars)

Pre-competitive Strategy Estimate Competitive Strategy Estimate NU’s Savings Estimate Percent Savings over Prior Year

1988

1989

$807 $738 $69 8.6%

$863 $812 $51 5.9%

Source: Decision Issued December 21, 1988 re Connecticut Light and Power, Docket No. 88-05-25, 100 P.U.R. 4th 452 1988 WL 391243, Section III.D. Policy Issues: Cost Containment and Productivity. Electric Operations total revenue requirements were $1.863 billion.

Millstone operating and maintenance costs were still in the range of 15.7 percent over two years. The filing also indicated that reductions in operating costs were to be accompanied by reductions in capital expenditures. There were to be no new major projects—only critical replacements of equipment already in place in existing facilities. Northeast specified that two projects were strictly necessary to sustain operations, the more important of which was the replacement scheduled in the 1990s for each of the Millstone Two steam generators at approximately $150 million.39 This was a large capital project, which would have been scaled back, but it constituted an outlay necessary for continued plant operation. The plan to implement strategy proceeded to focus as expected on nuclear operation and maintenance (O&M) costs. Cuts in that area were stringent, particularly in engineering, one of the activities central to the self-assessment and causal factor analyses that determine the sustainability of operations. By 1990, results were in line with the early targets set for the new strategy. An internal management study quantified the cost reductions, comparing actual costs with “business as usual” costs: If no changes had been made in 1987 and our expenditures continued to increase above our 1987 actual expense of $283 million at a rate of 5.5% per year, our total non-fuel O&M for the NE&O (nuclear engineering and operations) division would now be over $330 million. This tells us that the cost containment program has clearly resulted in [nuclear] costs today that are approximately $70 million less than what they would have been if no cost containment measures were implemented in 1987.40

In 1990 the first hint of operational effects from these cuts appeared in internal memos noting the impact of these cost containment efforts:

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TABLE 3.3 Nuclear Expenses for Millstone Facilities Adopted in CL&P’s Rate Case (thousands of dollars) Millstone Facility

Forecast Rate Year [1989]

Actual Test Year [1987]

Forecast Decrease from Test Year

One Two Three

$12,022 9,403 8,756

$13,001 12,001 10,730

$(979) (2,598) (1,994)

Source: Decision issued Dec. 21, 1988 re Connecticut Light and Power, Docket No. 8805-25, 100 P.U.R. 4th 452 1988 WL 391243, Section IV.G.2.F. Revenue Requirements: Company Expenses: Electric O&M Expenses: Nuclear Residual Expenses.

We have clearly become more efficient . . . and have in general made more improvements than we thought possible. At the same time we have increased demands on some of our employees beyond reasonable levels and have moved away from an overall proactive environment. . . . We are no longer in a proactive and anticipatory mode for chemistry. [The department] has been unable to respond to plant needs due to lack of certified instructors. There are insufficient resources to support the expansion of inspections. Updates of the FSARs [Final Safety Analysis Reports] is not being done adequately or in a timely manner. We are losing ground on maintaining our simulators as well as in modifying them to reflect the as-built plants. Technicians have been working 10% overtime for two years and are continuing to lose ground.41

As this memorandum clearly indicates, the initial cost reductions had an impact on Northeast’s operations, safety, and its relationship with its regulators. The cost cutting had succeeded in reaching percentage reduction targets. But the systems at the Millstone plants were being stretched to the point where forced outages began to occur, and there were no changes in the offing that would meet the post–Three Mile Island requirements of the NRC for enhanced maintenance, corrosion management, and new monitoring systems.

A Conceptual Framework for Analyzing Responses to Regulation Then where was Northeast’s strategic thinking at this point? The framework for answering this question has to consider management’s approach to the trade-off between cost containment and safety regulation. That approach centered on taking the chance of regulatory required nuclear-plant shutdowns as a “hazard” in a duration survival process. A

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chance of an occurrence of the hazard can be defined as a conditional probability of termination, in some period, given that termination did not occur in the first period.42 If the NRC did not require a Millstone shutdown in the prior period, then there was a probability that a shutdown would be required in the next period. Management continued with cost cutting given the hazard of a legally determined shutdown. If there was no shutdown this year, then management by its decision to continue to implement the strategy would incur some probability that shutdown would occur in the next year. The question is whether that probability was small or large. Consider the following example: Assume that X speeds on Central Avenue every day, in sight of the police who stop her with a warning that if she continues to speed, she will lose her license to drive. We are interested in the probability that the police, in stopping her in the future, will confiscate her license; did they tell her that “for certain” or did they tell her that “perhaps” it would be confiscated? Are the police more likely to lose patience as the number of warnings increase? In our judgment, the process through which Northeast strategizes its interactions with the Nuclear Regulatory Commission fits the hazard analytical framework. Our two hypotheses for explaining management strategy can be based on hazard rates that are either low and constant, or high and increasing. That is, the probability of an NRC-required shutdown is high continuously as warnings increase in severity during adverse events, particularly as events occur repeatedly on the same systems. Alternatively, the probability of such a shutdown is low, repeatedly, because the NRC does not intend to extend beyond warnings such an extreme decision. The interactive company/NRC process was as if either the hazard function was high over a range of adverse plant notices and events, or that it was low and then rose sharply at the end of repetitive notices. There are two functions of this description, known at least intuitively, that can be used to characterize the two hypotheses explaining the strategy: either “ordinary” or “extended risk.” Consider as a depiction of the ordinary strategy the SEV function, for which the hazard probability is exponential, increasing only slightly from zero for an extended number of events and then rising sharply at the end, as does the function shown in figure 3.2 for three values of the parameters (e.g., varying the NRC’s strength of response to the company’s inadequate response to the number of events). Alternatively, for the extended risk strategy, consider the IND function, used, for example, to describe the duration of strikes, the behavior of tracers in injections, and of purchase incidence in retailing.43 This is shown in figure 3.2 as a very high hazard probability, implying that the decision-maker “knew” of the high risk of a shutdown over a

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1.0 IND 0.9

SEV

0.8

Probability

0.7 0.6 0.5 0.4 0.3 0.2 0.1 0 0

5

10

15

No. of Events

Figure 3.2. Hazard Functions for IND and SEV Distributions. Notes: See equations in references listed in note 43. Calculations of three parameter values each, where values measure strength of regulator response. Inverse normal distribution with parameters (3,40), (3,30), (3,20), (y-axis is rescaled with ratio 2.4 to 1). For the SEV function, the extreme value distribution with parameters (50,5), (50,6), (50,7), (y axis is rescaled with ratio 1.5 to 1).

wide range of numbers of violations and from the NRC’s adverse reactions to these violations. We are not in a position to fit these functions to data on events which would allow us to conclude that one better describes Northeast’s risk appetite for shutdown in the 1985–95 period. Data on shutdown probabilities do not exist for different points in time, only subjective measures implicit in Northeast correspondence with the NRC, INPO, and others. As a conceptual exercise, however, we attempt in the narrative that follows to place data points subjectively on either an IND or SEV curve, based on judgmental estimates of whether the hazard probability was “high” or “low” for sequences of major regulation-related events over the period from the mid-1980s to the mid-1990s. The result is to make an overall assessment as to whether management “knowingly” incurred high risk of NRC shutdown as if it were on an IND curve, rather than on the SEV curve. To have been located on the SEV curve and to have continued the implementation of the strategy was not to have knowingly courted shutdown.

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Initial Results: The 1990–91 Millstone Nuclear Plant Shutdowns Operations at two Millstone plants went into forced shutdown for extended periods in 1990 and 1991 for a variety of reasons, described in a SALP report: Some shutdowns were due to employee performance and training. Millstone Two went into forced shutdown in October, 1990, due to operator errors in a routine test. In September 1991, three of five crews and eight of twenty operators at Millstone One failed examinations required for them to be certified to operate a nuclear facility safely. Because of a lack of certified operators, Millstone One was shut down and remained down until March 1992.44

Other shutdowns resulted from failures of coolant systems due to breakage and corrosion in piping, from failures of plant operators to meet competency-testing requirements, and from clogging in water filtration systems. These failures were of particular NRC concern, because these plant-piping systems had supposedly been subject to NRC-ordered inspection and corrective action at all three plants. Following an accident at the Surry Nuclear Power Plant in 1986, when rupture of a coolant feedwater pipe had resulted in fatalities and forced outage, and after several reports of more limited problems with coolant piping at other plants, the Nuclear Regulatory Commission had issued an industry-wide “generic letter” requiring all plants to establish new coolant piping inspection programs.45 To further this effort, the Electric Power Research Institute had developed guidelines and analytical tools to identify systems most likely to be susceptible to pipe wall breakage. The pipe breaks in 1991 at Millstone brought into question whether Northeast had used these tools to identify corroded pipelines and, indeed, whether it had carried out any of the corrective actions specified earlier. The Millstone water-system failures first occurred in two six-inchdiameter moisture-separator drain lines at Millstone Three on December 31, 1990. That event was followed on April 22, 1991, by a failure of a 11⁄2 inch drain line at Millstone Two and on November 6, 1991, also at Millstone Two, by failure of an eight-inch moisture-separator reheater drain line. Millstone Three was shut down during that time for pipe inspection as part of a renewed effort to determine whether there had been a widespread breakdown in evaluation and repair of pipe coolant systems at the Millstone site in response to the NRC generic letter.46 The reaction of the NRC to site-wide outage was to establish an augmented full-time inspection team to be located at Millstone. The team was sent to monitor the adequacy in general of the Northeast management response to the piping erosion / corrosion problem. The combined

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company/NRC review that followed determined that none of the failed piping at Millstone had been included in earlier Northeast system-wide erosion/corrosion inspection. The compliance program at Millstone was too narrowly based, and analyses of the line breaks at Millstone Two determined that the piping was below standards, so that it was not even in compliance with the facility’s original design.47 In addition to the piping problems, Northeast encountered severe problems in 1990 and 1991 with the screens that filtered water from Long Island Sound into the cooling systems of the Millstone plants. After a major storm, Millstone One experienced “mussel fouling” of screens, which partially blocked the entry of seawater. The problem was compounded by inadequate staff response to the slowdown of water inflow. In a subsequent review of the forced outage of the plant from this lack of coolant flow, the Connecticut DPUC found that the costs incurred were due to management imprudence and refused to pass the costs on to ratepayers. The decision stated, [A] substantial portion of the October 4, 1990, outage of the Millstone One nuclear generating facility was due to management or operational imprudence on the part of the Company. The damage to the traveling screens is a direct result of the Company’s imprudence. The costs to repair the traveling screens cannot be included in current rates. Connecticut Light and Power Company (CL&P) shall refund $2,865,000 to its ratepayers.48

Millstone Three went into forced shutdown on July 25, 1991, from loss of service water due to mussel fouling; further piping-system erosion / corrosion problems extended the outage until January 20, 1992.49 The SALP report issued August 4, 1992, for the period December 16, 1990, to February 15, 1992,50 indicated the sources of operational failures and then summarized the general performance at plants at the Millstone site: All three Millstone units were subject to long forced outages for programmatic and / or equipment problems including: Unit One for operator requalification retraining and erosion / corrosion; Unit Two for erosion / corrosion, steam generator (SO) tube leakage, and emergency diesel generator operability; and Unit Three for biofouling of the service water system and erosion / corrosion.51

As important as the operational failures, the Nuclear Regulatory Commission found that Millstone employee morale was either “very poor,” or “fair but declining,” and that the cause was that management did not provide leadership in working effectively to contain costs while sustaining the systematic quality of operations. In fact, employees and management were at odds on goal achievement at that stage of implementation of the strategy. Millstone management had not resolved cases of alleged

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employee harassment for reporting safety problems, nor had it adequately investigated questionable actions by supervisors. This had resulted in employee turnover and, subsequently, a speed-up in training new operators. The plant failures led to a significant drop in time that the nuclear facilities were on line producing electricity at the Millstone site. As shown in table 3.4, before 1991, Northeast’s nuclear facilities had a capacity factor (i.e., the percentage of available time in actual operations) of over 70 percent, above the national average of 63 percent for 1987 through 1990.52 In sharp contrast, in 1991 Millstone One and Three were each at 30 percent, and Northeast’s overall capacity factor dropped to 50.4 percent. Northeast had its Millstone nuclear plants on line and producing electricity less than half the time for the entire year.53 A further indicator of plant performance was the number of days in planned as well as forced outage. During this period, nuclear plants were down for refueling for approximately sixty to eighty days every two to three years. But the refueling period was extended if systems that had been performing poorly had to be repaired or rebuilt (i.e., in effect, planned outages were extended to include forced outage). Extended planned outages, and forced outages, if at high levels, suggest deviations from NRC-certified design according to license, that is, operations “out of design,” potentially subject to regulatory required shutdown. In 1990 the downtime at Millstone included 16 days of planned outage and 20 days of forced outage in Millstone One, followed by 131 days of planned and 113 days of forced outage in that plant in 1991 (see table 3.5). Assuming that sixty days were required for a typical refueling, then Millstone One was down more than five out of twelve months for system malfunction. There were 120 days and 92 days in scheduled outages at Millstone Two in 1989 and 1990, respectively, and 162 days of forced outage at that plant in 1991. Millstone Three, after a more or less normal 73 days of planned outage, experienced 173 days of forced outage in 1991. In all, the three plants at the site were each out at least five out of twelve months from forced (inoperable) conditions the first year and at least three months the second year. This plant downtime did not take place as a result of a series of unfortunate but mundane events. Instead it was a single catastrophe, of systematic failure, and had to be treated as such. Management responded by establishing employee self-assessment teams to find the “root causes” of the collapse of plant performance at Millstone. Four task forces of professional-level employees were commissioned to report on the extent of the underlying operational problems and to provide recommendations for solving them. Two of these task forces, on “causes” and “reportability,” produced findings on plant performance in terms much the same as

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TABLE 3.4 Plant Performance / Nuclear Capacity Factors (percent of available capacity in operation per year) Facility Millstone One Millstone Two Millstone Three Ct. Yankee Seabrook 1 Average (calculated)

1991

Start-up through 1990

30.8% 52.9% 27.9% 72.7% 67.6% 50.4%

71.4% (1970–90) 66.2% (1975–90) 75.4% (1986–90) 71.4% (1968–90) (in service June 30,1991) 72.4%

Source: NU, “Nuclear Information,” Northeast Utilities 1991–1996 Forecast and Financial Review, September 20, 1991, p. 13; Northeast Utilities Financial Forecast and Review, 1992–1996, April 1992, p. 15. CT DPUC Docket No. 96-10-06. NU Response to Interrogatories, Box 78508091.

those most critical in the SALP reports. The “root cause” report went further, into management / employee relations, and determined that “relationships between employees and management (first line and above) are significantly lacking in respect and trust; insufficient management sensitivity to employee issues which results in a failure to provide timely and objective resolutions.”54 The report proposed that corrective action TABLE 3.5 Plant Outages at Millstone Plants (days / year) Millstone One

Millstone Two

Millstone Three

Year

Scheduled Outages

Forced Outages

Scheduled Outages

Forced Outages

Scheduled Outages

Forced Outages

1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

59 8 77 0 53 16 131 0 0 130 58 0

4 17 4 7 9 20 113 120 13 10 18 366

138 93 1 73 120 92 2 216 14 92 197 1

47 7 23 10 0 7 162 17 41 94 31 314

NA 0 90 40 61 1 73 19 99 0 69 0

NA 29 15 36 28 39 173 84 11 14 0 276

Source: McGraw-Hill, Platts Energy Infostore, database “U.S. Monthly Operating Reports,” various months.

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“place emphasis on quality . . . without interference from other programs.”55 The report on “communications” recommended no change in procedures for communication with the Nuclear Regulatory Commission outside of “minor refinements.”56 The reports of the task forces were incisive on what constituted operational failure. The report on “procedural compliance” concluded that “procedure noncompliance is evident at the Millstone site,” in 50 percent of field observations. Most noncompliance involved safety of personnel rather than of reactor equipment, that is, “improper changes to procedures were observed to compromise the level of safety accomplished through administrative control.” This report described the lack of management focus as a contributing cause to procedural noncompliance: (1) inconsistent reinforcement of expectations as to safety in operations; (2) supervisors not accountable for worker noncompliance with safety requirements; (3) management not in the field or did not address safety problems in a timely fashion, or provide consistent signals on the importance of compliance with standards; and (4) vague and contradictory administrative procedures and inconsistent revisions of procedures. In summing up, the report placed responsibility on “a strong perception of lack of resources . . . [and] field interviews reported a widespread mistrust of management.”57 The plant “performance” report findings were that hardware limitations, poor individual performance, and a lack of recognition by management of the priority of nuclear engineering were integral to reduced plant performance.58 Since this report, along with the other three reports, was done by in-house engineers and staff, there had to be tension between those documenting the causes of operational failure and managers being accused of causing that failure. This may explain why detailed reports of numerous substantive problems that were discovered in the investigation are relegated to the appendix. The “bins,” or categories, of problems in performance that were listed in the appendix specify that “the programs we have put in place do not always reflect increasing standards for compliance.” The reason is that “[i]n general, we do not plan for or provide the resources to respond. Since a number require hardware modifications or significant amounts of resources, resolution is often deferred.”59 The conclusion was that the plants at the Millstone site were not operating at best-practice levels. The plants in general lacked design specification of the coolant systems, so that it was not possible to determine whether systems were “off design” when they malfunctioned. Functional requirements specification (FRS) was incomplete, so that, “in some [operating] issue the question is asked what was the requirement? The answer references . . . documents . . . [that] do not spell out requirements

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and today’s interpretation may be much more demanding than one of ten years ago.”60 At Millstone the nuclear engineering staff had been given responsibility for developing FRS for all plant systems, but “whether it had the resources to do it has not been addressed.”61 The recommendation of this task force was that management should require nuclear engineering to attain “excellence in performance and not cost containment” for the plants at Millstone to return to acceptable capacity factor levels. The report recommended, “This goal must be consistently communicated to all levels . . . as day-to-day business is evaluated.”62

Nuclear Regulatory Commission Early Warnings The Nuclear Regulatory Commission’s SALP reports on the Millstone plants for the 1985–90 period summarized the operating events of the period, rating each plant on four functional activities: operations, maintenance, engineering, and support.63 Each function was assigned a rating of one, two, or three, with a “one” representing a superior level of safety performance, a “two” reflecting satisfactory performance (but needs improvement), and a “three” deemed “acceptable” but likely to cause an increase in frequency of inspections. There was no score worse than three; a plant not reaching the “acceptable” three level was put on the Watch List to be considered for an imposed shutdown. The scores for the Millstone site plants fell slightly in the late 1980s; where it had once received scores of one, the scores were then falling to twos. At the same time, score averages were rising for the industry as a whole, so that Northeast’s decline moved against the national trend.64 (Table 3.6 summarizes Northeast’s SALP scores at the Millstone facilities.) The SALP reviews for 1990–92 fell to twos and to one three, across the board. The three was for “safety assessment” in all three plants, and indicated that Northeast should directly address safety deficiencies in a timely manner. Northeast was required to respond to the problems specified in the reviews. Most important, since the SALP took the position that Northeast had failed to address the root cause of employee concerns with plant safety, a new management procedure had to be developed for considering, addressing, and responding to in-plant employee communications on safety problems.65 The SALP scores on Millstone led to a meeting in March 1991 between Northeast and the Nuclear Regulatory Commission, which according to the Commission was “to ensure that the depth of the Commission’s concerns, relative to the licensee’s apparent inability to address the root cause of continued allegations, was clearly understood by NU senior management.” The Nuclear Regulatory Commission’s summary

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TABLE 3.6 Nuclear Regulatory Commission SALP Scores for Millstone Site Nuclear Plants

Category

Units 1, 2 6/1/86– 12/31/87

Unit 3 10/1/85– 2/28/87

Unit 3 3/1/87– 3/31/88

Plant Operations Radiological Controls Maintenance/Surveillance Surveillance Emergency Preparedness Security and Safeguards Outage Management Assurance of Quality Engineering/Tech. Supp. Training Effectiveness Licensing Activities Safety Assess/Qual.Verif

1, 1 2 1, 1 1, 2 1 2 1, 1 2 2, 2 1 2, 2 –

2 2 1 2 1 1 1 1 2 2 1 –

2 1 1 2 1 2 1 1 2 1 1 –

Category

Units 1, 2 Unit 3 1/1/88– 6/1/88– 6/15/89 0/15/90 1, 1 2, 1 1, 2 – 1 1 –

2 1 1 – 1 1 –

2, 1 – – 1, 2

2 Imp – – 1

Units 1, 2, 3 Units 1, 2, 3 Units 1, 2, 3 Units 1, 2, 3 6/16/89– 12/16/9– 2/16/92– 4/3/93– 12/15/90 2/15/92 4/3/93 7/9/94

Plant Operations 1, 1 Decl., 2 Radiological Controls 2 Maintenance/Surveillance 1, 2, 1 Emergency Preparedness 1 Security and Safeguards 1 Engineering/Tech.Support 2 Safety Assess/Qual.Verif. 2

2, 2, 2 2 Imp 2, 2, 2 2 2 2 3

2, 2, 2 1 2, 2, 2 2 2 2 3 Imp

2, 3, 2 – 2, 3, 2 – – 2 –

Source: NRC, SALP reports, dates as shown. Notes: SALP categories changed over time as indicated by blanks and changes in categories. “Decl” is declining, “Imp” is improving. Within each SALP report in the table, ratings are listed in order of plants reviewed by that report, as noted in the heading.

of the meeting noted that “the NRC sees NU as an outlier in the region, with respect to the number of allegations received from NU employees remaining very high for a significant period of time. This situation cannot continue to exist.”66 Commission concerns were not restricted to employee allegations about the safety of operations. Shortly after the meeting, the commission issued a Notice of Violation to Northeast for failure to follow safetyrelated procedures at Millstone Three that stated, “The repetitive nature of these occurrences (violations) indicate that previous corrective actions taken to improve procedural adherence have been inadequate and have

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proven ineffective in preventing procedural errors on eight separate occasions since February 1990.”67 The notice stated that their current procedures failed to determine whether faulty equipment and systems had been repaired or replaced. Indeed, there were no guidelines at all by which to check whether repair projects had been completed.68 The commission went beyond making critical evaluations of Northeast plant operations during the 1990–91 forced plant-downtime. In response to the four task-force reports, the commission sent a letter in November 1991 to Northeast’s CEO, William Ellis, noting that “several key issues need to be addressed, . . . includ[ing] the clarification, at all levels of your organization, of the relative priorities of cost containment and safety.” The letter recommended that Northeast “carefully analyze the results of all four task force efforts and integrate the findings of these efforts into a comprehensive plan to improve performance. We feel that such a comprehensive plan should contain clear management commitments for both short- and longer-term corrective actions. Further, this plan should include schedules for implementation, milestones, and measures of success and effectiveness.”69 The commission’s letter asked for a response centered on management’s view of performance at Millstone and specifying integrated recovery plans and schedules, to be discussed in early 1992.70 That December the Nuclear Regulatory Commission issued a public report on Millstone outages in the form of a Notice of Violation. The report concluded, “Weaknesses were identified in . . . management attention to erosion / corrosion control in the period following the Surry Station event (1986) through early 1991 . . . [even though management] had ample opportunity to avoid the break events that occurred at Unit-3 and Unit-2.”71 This Notice of Violation found basic fault with company practice, stating that a project assignment (PA) had been put forward by the group responsible for checking systems for erosion and corrosion but that it never received the implementing signature, and, furthermore, Had the PA been implemented, it is very likely that one or both of the largebore pipe break events would have been avoided. . . . Had the codes [developed for Unit Three] been used [at other units], the events at Unit Two may have been avoided. Although the codes were being used at Unit Three, they failed to identify the pipe that ruptured because of errors made in data input. Regarding the Unit Three pipe failure, the Unit Three staff failed to follow up on experiences of and at the other Northeast units by relying on direction from Northeast management, instead of following up on this area independently.”72

A second set of commission charges came in response to allegations of employee harassment and intimidation by Northeast management. The Nuclear Regulatory Commission established a Special Review Group

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(SRG) “to determine whether an atmosphere existed such that employees were encouraged to raise safety concerns, or instead had a ‘chilling effect’ on their willingness to come forward.”73 This group looked at the full range of complaints to the Nuclear Regulatory Commission and to the Department of Labor, and concluded that: an atmosphere that encouraged the reporting of quality deficiencies or safety concerns was lacking in many respects. The SRG found that weaknesses were present with respect to management direction and leadership that distracted from an open atmosphere for dealing with safety issues, including the more routine employee concerns. First . . . a micromanagement style of leadership existed at the senior management level. Employees and site directors apparently perceived an excessive amount of direction from corporate management on issues that were viewed to be properly site issues. . . . Secondly, Northeast Utilities management may have overemphasized cost containment. The lack of leadership and an “excellence in performance” goal was apparently confusing and demoralizing to personnel. In this connection, Millstone employees reported a strong perception of lack of resources.74

This set of serious charges, indeed condemnation, was based on the commission’s position that employee initiatives were critical for discovering and dealing with operating and safety problems. Only employees, interacting with management by coming forward with problems, prevented accidents and chronic unsafe conditions. Charges were increasing against plant-level management of harassment of employees who had come forward; they suggested that a working relationship barely existed. The local NRC staff warned Northeast management that it was at risk of encountering crises in its operating systems if this adversary relationship were to continue. Still, the NRC, in reviewing operations with senior management in the mid-February 1992 SALP exit discussions, maintained a delicate balance between positive assessments overall and negative findings or violations. It found that Northeast management had in place a possibly adequate process for corrective action to achieve safe plant operations (i.e., according to license design). But the negative findings on employee concerns in that period were numerous—half of the allegations of unsafe conditions from the Northeast (Region One) were from employees at the Millstone plants.75 The commission noted that the three plant forced-outages had led to notices of violations (NOVs). The mixed message was delivered by NRC staff in the Northeast boardroom with Chairman Ellis presiding. That message added to the “strain” on the commission / company relationship in keeping Millstone in the safe plantoperations category.76

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The LRS Report and CT DPUC After-the-Fact Appraisal The basic fault in operations of the Millstone plants was made exceptionally clear to Northeast management in a report in 1989 by LRS Incorporated, a consulting firm that made periodic appraisals of nuclear plant operations for Northeast. This report focused on the deteriorating working relationship between the operating engineers and plant-level management. In a decision in 1997, the Connecticut Department of Public Utility Control (DPUC) pointed to the LRS report, indicating that “the timeline for the decline in nuclear performance can be traced with certainty to 1989.”77 The report identified a number of similarities between conditions at Millstone and at a nuclear plant that had been placed on the NRC Watch List of problem plants. The report concluded that if the deteriorating performance were not arrested, “massive efforts would be required . . . that frequently result in the proliferation of paperwork, action item lists, commitment tracking of numerous get-well programs along with a major focus of attention on the formalized close out of some major, and innumerable minor, items.”78 The pattern of failure of Northeast’s operations in the late 1980s were seen to be at least partly the result of the breakdown of worker-management working relations. To turn that around required timely completion of the NRC Design Basis Reconstruction Program. The plan to do so had not been implemented, but, according to the DPUC decision, “Contrary to this recommendation, the Company’s own analysis [the NEEC Task Group Report] concluded that the Design Basis Reconstruction Program knowingly failed to meet industry standards, as set by INPO, and there was a definite lack of support for this program.”79 This approach resulted in “[l]ower ratings from the NRC [that in turn] result in costly, inefficient improvement programs that can have a significant financial impact . . . thus, maintaining excellence in performance is cost beneficial. And yet ‘the only consistent message received over the past four years is cost containment.’”80

Strategic Focus: Acquisition of Public Service of New Hampshire The third major facet of Northeast’s four-part competitive response strategy of 1986 called for expansion that would allow it to take advantage of its expertise and knowledge in new ventures outside the franchise region. In 1989 Northeast made a bid for Public Service of New Hamp-

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shire (PSNH), which was in bankruptcy due to its default on financing of its Seabrook nuclear facility. Public Service was the first major utility to undergo bankruptcy in fifty years, and as such, the acquisition presented unique complexities. Completion of the takeover occupied Northeast management for over three years, involving state governments, regulatory agencies, and the NRC in a “tar baby” effect. The way clear to complete the transaction was for the NRC to further regulate cost containment at the Millstone nuclear facility. PSNH entered bankruptcy after increased safety-related requirements— and difficulties with Massachusetts’ evacuation plans in the event of a catastrophe at the plant—extended start-up operations in the Seabrook nuclear facility over a fourteen-year period.81 The utility regulatory agency in New Hampshire would not allow Seabrook construction costs to be entered into cost for rate recovery until the plant was operational. Start up was delayed an additional three years after the plant’s completion by the lack of an emergency evacuation plan, which had resulted from the State of Massachusetts’ refusal to participate, due to opposition to the plant being located close to its border. Northeast made its first offer for PSNH in January 1989, for which negotiations took place over the next year. In Northeast’s initial offer, the Seabrook nuclear facility was not part of the purchase but was to be spun off to the PSNH unsecured creditors, but this condition was eliminated in later proposals. Within a few months, the bankruptcy judge entertained other offers, after the regulators in New Hampshire rejected a Public Service proposal for a 30 percent rate increase. More than two dozen generating companies stepped forward, and a series of bids and counter bids continued for months. New England Electric System made a bid structured similarly to that presented by Northeast, but with lower rate increases than those required by the Northeast plan. Central Maine Power and Central Vermont Public Service announced a “study” of a merger leading to purchase of some of the assets but later decided not to pursue an acquisition.82 Over the next several months, Public Service worked with its creditors, as well as the State of New Hampshire, to define a reorganization plan that did not require a buyout. Northeast and New England Electric both revised their bids, and Public Service continued to negotiate an internal reorganization plan that would have the support of creditors. A new player entered with a merger proposal, United Illuminating Company— the New Haven, Connecticut, utility—whose plan would merge the two largest owners of Seabrook—UI’s current share of 17.5 percent of the plant assets was second only to PSNH’s 35.6 percent share.83 A difference in settlement terms was solidly established between the regulatory agency seeking to hold down rates, and creditors seeking value for assets,

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which prevented agreement between the bankruptcy court and state regulator. But the bidding continued, with revisions and improvements of the offers from the remaining interested parties. In the midst of these negotiations, the Seabrook impasse on plant start-up was finally resolved when, in November of 1989, the utility’s evacuation plan was approved, without (or in spite of) Massachusetts. The Nuclear Regulatory Commission voted to license the plant in March 1990, with full power operation expected after a several month phase-in period.84 From late November 1989 through March 1990, Northeast’s bid gathered support from Public Service creditors, shareholders, the board of directors of Public Service, and also New Hampshire legislators. Finally, with the support of the bankruptcy court, Northeast’s bid succeeded, and it began supervising the New Hampshire operations as of April 30, 1990.85 In the process of succeeding, numerous conditions were offered that made it difficult for this acquisition to become a strong part of the Northeast competitive response strategy. We are not in a position to judge whether Northeast was subject to the winners’ curse, because we do not have management’s estimates of present value of future cash flow that would have resulted from adding the plant to the Northeast nuclear portfolio. But management agreed to conditions on O&M costs at Millstone that it would later not fulfill. The key condition of the NRC for the transfer of the Seabrook operating license to Northeast was a new plan for NRC intervention in strategic cost control at Millstone. In its deliberations on transferring the Seabrook license to Northeast, the commission questioned the adequacy of Northeast resources to sustain its current nuclear operations. In a highly unusual move, the commission then required that Northeast increase spending to restore Millstone facilities, as a requirement for Northeast to acquire the license for operation of Seabrook. In a May 1992 meeting on the proposed merger, the NRC had made clear how its safety concerns with Northeast Utilities affected the Seabrook license decision: A matter of significant concern to the Commission while considering this merger request has been the allegations of intimidation and harassment of employees reporting potential safety concerns against Northeast Utilities in conjunction with its ownership and operation of the Millstone facility. It is important to understand that the crux of the Commission’s interest is whether as a result of this merger Northeast Utilities will have the capabilities, both financially and managerially, to safely operate the five nuclear plants that would be under your ownership and control.86

In terms and conditions for the Seabrook license, the NRC required Northeast to commit to a “Performance Enhancement Program” (PEP),

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with new outlays for hiring up to 250 employees, and for expansion of corrective action programs, at the nuclear facilities at Millstone and Haddam Neck (the Connecticut Yankee plant). Moreover, Northeast had to pledge to keep Seabrook management separate, in terms of operations and maintenance, so that below-standard practices would not spread from Millstone to the new facility.87 The unusual rationale for terms requiring changes in one set of plants to receive permission to operate another is revealed in an exchange in the decision conference. In the transcript, the discussion is between Commissioner Forrest J. Remick and Thomas E. Murley, the Director of the Office of Nuclear Reactor Regulation, following a presentation by commission staff on the conditions for the license transfer: Commissioner Remick: I understand that these conditions are new for this license, but have we imposed such conditions on any previous licensee of this general type? Doctor Murley: Not that I’m aware of. Commissioner Remick: So this would be the first? Doctor Murley: The focus—I think you’re quite right. The focus that the staff has had is on keeping what we call the Millstone virus from going to Seabrook. That’s what the proposed conditions are.88

Plant operating rates in 1990 and 1991 had convinced NRC staff that Northeast nuclear performance was as bad as a “virus.” Outside consultants, internal task forces, and NRC staff all expressed concern with this performance along the same lines, if not with exactly the same perjorative. As a result, requirements for the transfer of the Seabrook operating license were extended to include “written assurances that adequate financial resources would be provided for nuclear operations at Seabrook as well as at the Millstone and Haddam Neck facilities.”89 The commission required Northeast to develop a specific plan for the Millstone plants, to document resource requirements to carry out the plan, and through 1995, to report annually on spending. The Nuclear Regulatory Commission authorizing letter warned that “the resources projected to be applied to improving the safety performance of the Northeast Connecticut nuclear plants will not be reduced until the Nuclear Regulatory Commission Staff is apprised, on a timely basis, of those projected changes and the reason for those changes.”90 The Nuclear Regulatory Commission expressed its general position in 1992 on Northeast management and strategy in a letter finalizing the license transfer, sent June 3, 1992, to Chairman Ellis and members of the Northeast Board of Trustees. The commission took the position that Seabrook could be operated safely under Northeast management but stated that “additional precautions are necessary to ensure that Seabrook

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operations are not adversely affected by Northeast Utilities policies and practices.” The Nuclear Regulatory Commission solicited the support of each member of the board “in resolving the Nuclear Regulatory Commission’s concerns about performance at the Millstone Station.”91 The general concerns were expressed in strong language: Over the past several years, cost containment initiatives and Northeast Utilities management’s approach to addressing employee safety concerns at the Millstone station could have an adverse effect on the continued safe operation of these facilities. While we recognize and endorse the recent initiatives and formulation of plans by Northeast Utilities to improve the overall safety performance of their nuclear stations, we remain concerned in that these plans have not yet been finalized, implemented, and demonstrated to be effective in improving safety performance, allocating adequate resources, and addressing employee concerns.92

The acquisition of Public Service gave the Nuclear Regulatory Commission a new hold on Northeast. The company had to increase resources available to the nuclear program at Millstone if it were to be allowed to operate Seabrook, and it committed to do so through this Performance Enhancement Program (PEP). This commitment was in conflict with cost containment strategy and would have required a turnaround in cost containment at Millstone and abandonment of important short-term profit goals for the company as a whole. This did not happen. Instead, this commitment, too, would be subject to cost containment later in the decade.

Initial Results: Financial and Nuclear Plant Operating Performance Events at the Millstone site in 1990 and 1991 raised questions as to Northeast’s ability to provide adequate safety in the operation of its nuclear plants. Northeast had serious problems with employee relations, particularly its treatment of “whistle-blowers” on safety violations in the three plants and generally in communicating safety issues. The central concern remained whether in-plant cost-cuts in maintenance and replacement of equipment were causing coolant and control system failures. But this concern was operational at the plant level, with limited effect on corporate financial performance. The loss of production from plant shutdown did not have an immediate impact on earnings of the corporation. The reason was that regulatory accounting limited the impact: repair costs and the costs of replacement power were booked to “recovery accounts” based on the expectation that the company would be allowed to collect future revenues to cover these deferred expenses. Northeast financial results, in fact, continued to improve—earnings in-

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creased each year after 1989, and 1991 earnings were more than 9 percent above those for 1990. In spite of shutdowns, cost containment continued to achieve strategic targets, with 1991 budget reductions estimated at more than $100 million. A voluntary early retirement package was offered in late 1990, at the height of Northeast’s operating problems, and accepted by 400 employees, bringing the total work force reduction since 1987 to more than 1,100 and resulting in payroll savings estimated at $27 million annually.93 The major challenge for Northeast posed by the nuclear plant shutdowns was whether continued implementation of its strategy would involve even more conflict with NRC safety regulation. Cost containment in nuclear was central to the competitive strategy. Nuclear-operations cost containment had led to savings of nearly $70 million per year by 1990.94 It could not be sustained, however, beyond the $100 million realized in 1991. Nuclear system problems with piping erosion / corrosion, and faults in variations from design specification, associated with cost cutting, had developed negative feedback that caused emergency and out-of-budget spending to increase. That is, cuts in the 1985–89 nuclear budgets caused operational problems that required increased outlays above nuclear cost-containment budgets in 1991–92. NRC-required additional outlays, forthcoming in the new Performance Enhancement Program, was supposed to reverse budget cutting further. Company management was faced with having to achieve cost reduction targets, outlined in the strategy, against increased expenditures for nuclear plant operations. The decision to increase spending to meet NRC requirements, however, did not signal an abandonment of the strategy. After the 1991–92 disaster changing the strategy would have required a commitment to: (1) a “return to excellence” by restoring pre-cost containment budgeting and (2) establishing a reconstruction and renovation program at the three Millstone plants to attain operational load factors in the 90 percent range. Of course this reversal or rejection of low-cost dominance strategy in nuclear would have been costly. It is impossible to estimate the costs that would have resulted had Northeast reversed strategy at the beginning of 1993. A full audit of all failed and suspect systems and the resulting costs of renovation or replacement would have been required. But we can hypothesize, using certain assumptions, as to what it might have cost in “order of magnitude.” Even that rough estimate is revealing. For the purpose of achieving SALP level-one standards in the seven most important categories, the Millstone plants would have to have been closed down for evaluation, renovation, and repairs as they were under the NRC imposed shutdown in 1996–98. The early retirement of Millstone One and reconstruction of Millstone Two and Three required

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write-offs of $260 million in 1996, $215 million in 1997, and $215 million in 1998.95 Operations and maintenance expenses increased by at least $116 million in 1996, $144 million in 1997, and $172 million in 1998 in the reconstruction (as indicated in the Northeast Utilities 1999 Annual Report). If we ignore inflation and the additional costs of the heightened NRC scrutiny in 1997–98, and assume that these costs would have been the same in 1991—that is that the 1996–98 reconstruction would have solved the 1991 operational deficiencies—then the two-tothree year costs of reconstruction of Millstone would have been approximately $1.1 billion. Some part of that spending could have been recorded in deferred “recovery accounts,” as the basis for later rate increases. Even if the changes that Northeast expected in market competitiveness had occurred, changes that had caused Northeast to adopt cost containment, utility commissions could have justified allowing utilities to recover these amounts as “stranded costs” in short-term rate additions. If the regulators rejected the argument for recovery, management would have been faced with reduced earnings in the range of $1 billion, which constituted 40 percent of total earnings over the next four years (see table 4.4, Northeast Utilities Consolidated Financial Performance, 1991–95). This estimate of earnings reduction is surely high; for one, many of the 1996 costs for Millstone Two and Three renovations were the result of problems specific to plant malfunction in 1993–95. But if these additional costs were only half a billion dollars, abandoning the strategy in the early 1990s at that expense should have led even a passive board of trustees to discharge management. By electing to fix the “nuclear problem” in the early 1990s, management would, in effect, be firing itself. Nuclear renovation costs would have significantly reduced corporate earnings, so as to leave Northeast with losses throughout the middle of that decade. The alternative for management was to continue with the cost containment strategy, taking the risk that either the Nuclear Regulatory Commission or deteriorating plant operating performance might require an even more costly fix later in the decade. In the interim, however, maintaining the strategy would add to earnings, adding to management’s own salaries, bonuses and stock awards, with expectation of continuation well into the 1990s.

Four Revisiting Competitive Strategy in the Mid-1990s

Following its nuclear operating setbacks in 1991–92, Northeast got on track with the two most important parts of the strategy: expansion to New Hampshire and further implementation of company-wide cost containment. It encountered renewed problems and regulatory warnings at the Millstone nuclear plants, most particularly with regard to operating performance at Millstone Two. But when it had to initiate PEP, the Performance Enhancement Program, at its Millstone facilities to meet NRC licensing requirements for Seabrook, it “cost-contained” the increased spending in that program.

Northeast Strategy and the Competitive Threat Northeast completed the steps required for the acquisition of Public Service of New Hampshire by June 5, 1992. The investment outlay was $941 million, consisting of $789 million in cash to PSNH common stock holders, and $152 million for merger-related expenses, taxes, and reduction of short-term debt. Northeast financed the purchase through sales of common shares to the public of approximately $222 million and to its employee stock ownership plan of $250 million. It also issued $355 million in mortgage bonds on New Hampshire assets, with short-term borrowing of the remainder.1 With this expansion program in place, Northeast Utilities developed new programs for further completing the strategy throughout 1992–95. Cost containment was pursued in every part of company operations, through programmatic top-down reviews that stressed the necessity of doing more than then-current-year budget reduction targets. Into the mid-1990s, the development of budget-review procedures put senior management in the position of exercising tighter spending controls on the three Millstone plants. Implementation of increased spending under PEP accelerated. Also, poor plant performance required emergency spending to restore operations after forced outages. Northeast specifically headlined cost control in its budget-based programs. In early January of 1991, corporate management initiated a new comprehensive and rigorous budgeting procedure that had implications

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for nuclear operations. Mr. Bernard Fox, Northeast’s president and CEO, set up a “senior budget review committee,” which was to pass down budget aggregate targets to “functional budget review committees” (FBRC) that would oversee implementation and monitoring at the division and ultimately the plant level. The key nuclear operating personnel—Messrs. Boguslawski, DeBarba, Graves, Mroczka, Opeka, and Sears—formed the nexus of the FBRC. They were to be responsible for achieving more stringent budget targets; for example, in August 1993, the target was to reduce budget spending levels consistent with “price assumptions” that allowed Northeast to compete with other sellers in deregulated wholesale power markets. This was necessary to attain the “financial security of the company,” based on higher earnings and dividend growth. To attain these implicit cost-reduction targets, controls on actual spending compared to budget were to be set by “core process reengineering” from benchmarking studies. Four-year targets called for annual 5 percent reductions in nuclear non-fuel O&M expenditures; for all other operations the reductions were targeted at 10 percent of operating costs and 5 percent maintenance costs. It was suggested that members of the FBRC share the memorandum on cost-containment goals “throughout the organization to enhance the understanding of Northeast’s goals and strategies.”2 The 1991 Annual Report stated that the company “had reduce[d] budgeted expenses by $101 million, contributing directly to better-thanexpected earnings and reducing pressure on rate filings.” The report went on to note that in the fall of 1991 over 400 employees agreed to early retirement, to be implemented in 1991 and 1992, and it estimated payroll savings at $27 million annually. But the operating performance of the Millstone plants was characterized as “less than satisfactory,” a statement provided at the end of the report.3 Northeast described cost containment as follows: “[S]ome of the spending cuts represented postponements, but many will become permanent . . . [as we] fundamentally address the way we will conduct our business in the future.” The company announced the development of five-year business planning as a key step to meeting the emerging competitive threat in wholesale markets. The essay in the Annual Report was by Eric Zausner, a well-known energy industry analyst, whose message was a simple one: “[I]t is not a regulated industry any more, it is a dynamic, market-driven enterprise.”4 Looking back on the first few years of the strategy, the management of Northeast considered cost reduction to have been successful. In 1992, Bernard Fox made a presentation to an EEI Financial Conference, entitled “Strategy to Meet Competitive Threat,” on a return visit after four years to update this conference on the implementation of the strategy. He

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noted, “I’m pleased to report that our strategy is working. We have expanded geographically. We have established new energy-related subsidiaries. We have become more competitive and we are improving our financial performance.” He pointed to the acquisition of Public Service of New Hampshire as making it possible for Northeast to double the size of its service territory and to increase customers by 25 percent.5 The speech focused on the challenge of meeting “the competitive threat” by noting, “We knew we had to become a lower cost producer, and, like the rest of the industry we’re moving in that direction through aggressive cost management and downsizing.” He stated that Northeast had reduced its system work force by more than 1,500 positions over the first five years, and it had achieved a reduction of operations and maintenance expense levels of $175 million. He presented the new nuclear spending program, PEP, as requiring additional outlays, but explained that the outlays were manageable within the plan’s framework. He described PEP as adding 450 positions to the nuclear staff of 2,000 and increasing planned plant O&M capital expenditures by $40 million annually for each of the next three years. He went on, “[T]his commitment brings our nuclear operations and maintenance [cost] growth rate over the 1992-to-1996 period to about 5 percent.” He noted that work force reductions in other parts of the company should be sufficient to prevent total employment from increasing.6 Mr. Fox went on to note, however, the need for additional and extraordinary cost-containment measures to make Northeast “competitive” in the 1990s. On the retail level, Northeast expected to work with the state regulatory commissions to restructure its rate schedule, reducing industrial rates to attract and maintain industrial customers. On the wholesale level, its contracts supplying a dozen retail utilities for more than 1,400 megawatts of power were not likely to be renewed at the then-current price levels over the next few years; it had to be prepared to sell into the bulk regional power pool at lower prices.7 Market conditions required costs per kilowatt-hour of produced power to be reduced, to levels lower than those already planned from cost containment, in order to sustain positive margins on both wholesale and retail industrial sales. The presentation made it evident that Northeast had not resolved the conflict between predictions of low market prices and high nuclear generation costs. The PEP program as outlined would drive nuclear generation costs higher. Savings in non-nuclear generation might improve the outlook for company costs as a whole, but nuclear production was its marginal supply into the power pool. Further reductions in nuclear generating costs were required. In 1992 hearings before the Connecticut DPUC, Northeast compared

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its costs with those of non-utility generators. Northeast’s generation costs averaged 5.5 cents per kilowatt-hour for fossil and 8.5 cents for nuclear power. Northeast’s competitors reported non-utility generation costs that ranged from hydroelectric power, as low as 3.2 cents per kilowatt-hour, to a limited number of waste-to-energy facilities, as high as 13 cents per kilowatt-hour. But mid-range non-utility generation, from newer coal and natural gas plants, were expected to comprise the major source of competitive supply; their costs ranged from 5.3 cents per kilowatt-hour to 7.6 cents per kilowatt-hour, competitive with Northeast’s fossil but lower than Northeast’s nuclear costs.8 The 1993 Annual Report focused on a new approach. The costcontainment strategy is described as having been “revised,” even though the dedication to the cost-containment goals remained unchanged. Reducing costs was still the cornerstone, but Northeast now would “focus on restoring excellence to its nuclear operations.” The management system was reorganized, with support personnel moved closer to operational personnel and “process reengineering” instituted to “apply modest, incremental changes to its processes, where appropriate, to build a sustainable competitive advantage, but also to make radical changes where essential.”9 This rhetoric was built on the view that operation rates in the nuclear plants had to improve. Northeast nuclear capacity utilization did improve with all five units operating at a combined factor of 86.6 percent in 1993. In addition, state regulators allowed retail prices to increase after Northeast’s largest retail subsidiary, Connecticut Light and Power (CL&P), completed a long and arduous rate case and was allowed three annual rate increases of 2 percent a year, collecting an additional $141.3 million in revenues, with an additional $100 million authorized for recovery but deferred until later.10 Both production rates and prices were not moving in the right direction for “strategy to meet competitive threat,” but for increasing current profits. The theme of the 1993 report was “The Power of Change,” with the goals to “enhance customer focus, become more market-driven, reduce costs, expand market share, and increase profitability.” Messrs. Ellis and Fox, in their letter to shareholders, described the 1990s as the “decade in which Northeast Utilities embraces fundamental and dramatic change.” The company was to increase profitability by providing better service and reducing costs to stabilize price to consumers.11 Nuclear facilities were to reach high-level capacity factors, and the nuclear organization was to be “reshaped” with both new personnel and changed responsibilities. Mr. Robert Busch, chief financial officer, was promoted to the position of president of the new Energy Resources Group, and made responsible for the operations of all generating facilities as well as the finance, accounting, and treasury groups.12

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Not all the major steps were in the direction of “the power of change.” The McKinsey consultants’ meetings with Northeast in 1992 and 1993, aimed at updating the 1986 competitive strategy, called for more cost reduction, asset restructuring, and increased pricing flexibility. The lower prices to be expected in deregulated wholesale markets would require reductions in current operating and capital expenses in the generating facilities; this became even more clear when Northeast announced in mid1993 that it was again intensifying cost reduction across the company, through programmatic reengineering that would reduce the employee payroll by another 600 to 700 personnel before the end of the year. Northeast’s five-year business plan for 1994–98 for nuclear engineering and operations areas had growth rates for operating expenses well below those for fossil, with a decrease in nuclear capital budgets, compared to an increase in fossil plant capital spending.13 An internal financial report in May 1994 noted “considerable progress . . . in the past nine months, [including] . . . reducing payroll by eight percent and significantly reducing capital spending to levels well below those projected in the fall of 1993.”14 To extend these reductions even further, the company called for early retirements and layoffs to reduce the work force by 20 percent over five years. Because the PEP required increasing the number of nuclear engineering and operatives employees, more retirements among other employees would have to take place at the nuclear plants to attain these goals. Cost containment returned to center stage as the primary initiative in the next year’s Annual Report. Based again on the adverse effects of competition in power generation on company earnings and growth, management called for achieving the low-cost position. The letter to shareholders from Messrs. Ellis and Fox in the 1994 Annual Report emphasized that the “critical strategic issue facing the company and the electricutility industry is—and will continue to be—competition.” The report noted, “We are working hard to benefit all our customers by keeping prices competitive, beginning with rigorous cost management.” The 1994 report featured a guest essay by Barry Abramson, a Wall Street utility stock analyst, who emphasized price competition in electric markets and noted that utilities would have to cut costs to avoid reduced earnings.15 But it was not competition that drove the financial results that year for the company. The 1994 Annual Report showed an increase of 14 percent in earnings, the most substantial in a decade. Total returns to shareholders (stock price increase and dividends) for the year were more than 13 percent above that of the Dow Jones Utilities Index. The report noted that, “far more important than a single year’s increase in earnings, the Northeast Utilities system made major strides in strengthening its competitive position and improving its fundamental cost structure.” The

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shareholder letter emphasized the company’s strategic approach: “We will be successful in a more intensively competitive environment only with the strategy, the systems, the skills, and the staff to navigate through the transition from a regulated monopoly to a market-driven enterprise. The rapidly changing marketplace is demanding stable and even lower prices for electric energy.”16 The implications are the same, however, without Northeast being “market driven”: Northeast was generating significant increases in earnings from cost containment, in the absence of incursions from any new “competitive threat” in retail and contract markets. There were, moreover, gains in the wholesale market supply, where it had been expected that Northeast would be closed out. The report on the wholesale market noted that 13 percent of company revenues were from wholesale market sales, and, “according to the report, current significant surplus of wholesale power in New England and New York, NU’s more than $330 million in wholesale revenues are under extreme pressure. Ironically, the company is selling more kilowatt-hours in this market than in the past, but realizing fewer revenues because of surplusdepressed prices. NU is committed to building on its successes in the wholesale marketing sector.”17 The 1994 wholesale revenues of $330 million were down from the prior year’s $383 million (see table 4.1), but were still 10 percent above levels in the late 1980s. TABLE 4.1 Northeast Utilities Sales and Revenues (millions of dollars) Wholesale and Bulk Power

Total Electric

Year

Sales (MM kWh)

Revs (MM $)

Avg. price ($/kWh)

Sales (MM kWh)

Revs (MM $)

Avg. price ($/kWh)

1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

5,883 4,284 4,711 5,351 5,394 5,388 7,733 9,046 9,123 8,718 8,082

234 204 228 301 346 366 347 383 331 303 324

0.040 0.048 0.048 0.056 0.064 0.068 0.045 0.042 0.036 0.035 0.040

27,535 26,990 28,585 29,547 29,611 29,300 35,076 39,217 40,046 39,618 39,474

1,962 1,983 2,221 2,426 2,563 2,697 3,161 3,567 3,585 3,685 3,710

0.071 0.073 0.078 0.082 0.087 0.092 0.090 0.091 0.090 0.093 0.094

Source: NU, “Consolidated Electric Operating Statistics,” Northeast Utilities, annual reports, various years. Notes: For 1986–89, bulk power sales are combined with wholesale revenues to conform to FERC’s 1990 reclassification of bulk power sales from operating expense to revenues.

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But Northeast had other regulatory reasons to be concerned about future prices. A 1994 decision by the Connecticut DPUC stated that there were three reasons for the state’s high wholesale rates: (1) the high cost of nuclear, (2) surplus capacity, and (3) high purchased power costs due to PURPA requirements for purchasing from alternate sources at a high mandated price. The department noted that Connecticut was dependent on nuclear generation for 65 percent of its power generation, compared to 22 percent nationwide, and only 9 percent of its power came from low-cost coal and natural gas, compared to 65 percent across the country. On the other hand, the department reiterated its concern about operating risks of incumbent utilities having to reduce costs in nuclear and noted that there were “serious questions of equity and regulatory responsibility.”18 The “competitive threat” was still seen as looming on the horizon, even though the horizon was no closer. Industrial customers in the near to far future would be seeking wheeling agreements to bring in power from outside New England using Northeast transmission lines. A number of outside providers had lower-cost power than Northeast, but few of those had excess power that could be made available to Northeast customers (as in table 4.2). The implication of such a “competitive threat” was that it might be out there, but there were no “deep incursions” into Northeast’s customer base from retail competitors by 1990, as had been predicted by McKinsey and the company’s senior executives in 1986. Rather, cost containment was justified only if nuclear kWh marginal costs were greater than wholesale prices within the next five to ten years. Competition remained on the horizon, and perhaps by this time the horizon would not move away. In the interim, the near-term result of containment included significant increases in annual corporate earnings. If Northeast brought its costs down to the average of that of alternative service providers over five years, it would have to eliminate costs at a 10-percent rate. As table 4.3 shows, generation costs of Northeast’s nuclear plants, including fixed capital as well as costs required for ongoing operations, were highest at Millstone Three and Seabrook—the newest and largest plants providing the marginal source of supply into the New England pool and the contract wholesale markets. The marginal costs exceeded the average costs of the New York Power Authority, Niagara Mohawk, and Pennsylvania Power and Light. By the mid-1990s, nuclear generation, and the new plants in particular, faced three challenges: (1) unrecovered previous capital outlays, (2) escalation of operating and maintenance costs, and (3) capital and operating costs of decommissioning, which were included in ongoing rates charged to retail customers. The first challenge was the high level of nuclear capital in Northeast’s original book costs that were still not re-

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TABLE 4.2 Cost of Power Generation and Capacity Availability of Potential Competitors

Regional Power Producers

Generation Cost (cents per kWh)

New York Power Authority Niagara Mohawk Pennsylvania Power and Light Public Service Electric and Gas NEES-Narragansett NEES-Mass Electric NU-PSNH NU-CL&P NU-WMECO United Illuminating EUA-Blackstone EUA-Eastern Edison

2.3 5.1 6.1 7.5 8.6 8.0 8.7 8.1 9.1 9.1 9.6 10.0

Est. Surplus Capacity (MW) 650 650 (200) *550

100 **250

Source: Electric Light and Power Journal, September 1992, pp. 2–27. In addition to these estimates, the New York Power Pool had a surplus of about 3,200 MW, which was expected to rise to about 4,000 MW by the year 2000, at generation costs to be estimated. Notes: *NEES Total. **EUA Total.

covered in depreciation. Nuclear investment, particularly in Millstone Three, represented over 50 percent of the total book assets of the company. Although the investment was earning a regulated return under current utility pricing rules, recovery of these assets would make it impossible to lower regulated prices in the foreseeable future.19 Second, higher operation and maintenance costs associated with PEP could drive up nuclear costs relative to other generation costs. The third challenge resulted from future decommissioning; Northeast to date had set aside reserves TABLE 4.3 1995 Marginal Costs of Power Generation at Northeast Nuclear Plants (cents per kilowatt-hour)

Millstone Two Millstone One Ct. Yankee Seabrook Millstone Three

Capital Cost

Variable Cost

Total Cost

1.4 0.9 1.7 4.0 4.9

2.6 3.5 3.8 2.4 2.8

4.0 4.4 5.5 6.4 7.7

Source: Northeast Utilities, annual reports, various years.

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equaling less than a quarter of expected decommissioning costs of the nuclear facilities. Any reduction in expected future plant-generation of kWh would require an increase in rates charged for current generation to build up the decommissioning trust over a shorter plant lifespan. Northeast’s spending on PEP in the nuclear facilities increased its total O&M outlays in the mid-1990s. The extent of the spending, however, was cost-contained, and was less than required to return the plants to full compliance in operations. Spending for the PEP program was required by the NRC, but not the full program. Recovery from forced outages in 1991 and 1992 inevitably required catch-up spending to return to operational levels. As was recognized at the time, reduced spending in the 1980s on preventative measures led to more expensive emergency spending later. In all, the mid-1990’s add-on to O&M outlays can best be described as the result of tactical decision making, not a change in strategy; they put Northeast in the position of implementing cost containment while experiencing higher-than-budget costs per kilowatt-hour of production. The primacy of competitive strategy and the conflict with other regulatory requirements in this period were chronicled in a study undertaken later for the Connecticut Department of Public Utility Control by consultants R. C. Brown and Associates. They evaluated Northeast’s strategy based on document review and interviews with Northeast personnel. The resulting “Brown Report” noted that cost control conflicted with plant safety at Millstone, a conflict “in some cases dating back to the late 1980s.” The result had been that Northeast had developed a number of initiatives over the years that suffered from a lack of management direction and commitment, with the result that [they] were generally ineffective in addressing and resolving the NRC’s concerns as well as achieving the goals of the corporate strategy.20 The Brown group evaluated both PEP, in place from 1992 to 1994, and the “Improving Station Performance” (ISP) program, developed internally in 1993 as a replacement for PEP, but never implemented. Its conclusions were that “NU’s failure to achieve effective results from either PEP or ISP was largely attributable to a preoccupation on the part of executive and senior management with the cost and financial implications of operating its nuclear units, heightened by concerns over the pending deregulation of wholesale and retail electric markets.” PEP was merged into the company “Business Plan,” and ISP was absorbed into a long-term initiative to reengineer the nuclear organization. The Brown report stated, “As neither NU’s Business Plans, nor the Reengineering initiatives were sufficiently focused on the short-term deficiencies within the Nuclear Organization, NU was unable to effect positive change in a timely manner.”21 The company used the PEP program and reengineering

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to identify operational problems in nuclear but not to solve them. To correct the operational failure resulting from deep cuts in plant infrastructures required outlays that would have compromised the costcontainment strategy.

The PEP Process for Improving Nuclear Plant Performance The PEP program was intended to correct the faults that caused forced outages in 1991 and 1992 at the Millstone plants.22 The first report, presented by management to the NRC regional staff in April 1992, focused on problem identification, based on the findings of the four self-assessment task groups after the forced outage events. At the presentation, Northeast stated that 27 percent of some fifty-six task group recommendations had been completed, with most of the remainder to be completed in the coming year. Northeast also stated that an action plan had been developed and $10 million had been added to the 1992–96 budgets to undertake “straightforward and narrow scope items first,” including putting more supervisors in place, creating assessment centers, and establishing procedures for dealing directly with operational failure in systems. The report stated, however, that “more complex and resource intensive items were in process” including upgrades of important safety procedures and renovation of “design basis” programs.23 The timetable initially established for PEP had three phases. The first, to begin in 1992, included data collection, validation, and root cause analysis. The second phase, overlapping with completion of the first, included development of more complex action plans and initiation of problem solving. The final phase consisted of completing action plans and then validating effectiveness of these plans in achieving problem solutions, to be completed by 1994.24 The first months went as Northeast had promised: in April 1992, it committed $10 million and 200 additional employees to the nuclear organization, “to improve operational and training resources.” According to the company, “The measures were designed to restore Northeast’s leadership position in nuclear operations.”25 In June 1992, Northeast announced that it would add 250 positions to support restoration of plant operating performance at the three Millstone nuclear generating units as well as at the Connecticut Yankee unit. These new positions were in addition to the 200 positions announced earlier, and they would lead to the realization of the projected annual budget increase of $40 million per year.26 In its 1992 Annual Report, Northeast described efforts to restore nuclear operations to high levels of excellence and noted that by “the end of 1994, NU will have added as many as 450 additional nuclear employees

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and, by the end of 1997, will have spent up to $210 million more on nuclear operations than had been planned for this period.” In the financial and statistical section of the report, however, it presented specifics as to how far the company was from achieving excellence in nuclear operations at Millstone, noting that performance was “less than satisfactory in 1992 despite some improvement over 1991.”27 At that point, Northeast stated that PEP would provide “aggressive management actions [which] were needed to address detailed action plans to improve performance.” It described the program as follows: Over the four-year period, approximately $15 million will be allocated to reduce the engineering backlog for the Millstone and Connecticut Yankee units, and approximately $14 million will be allocated to continue the procedural upgrade effort of the Millstone units. The Nuclear Engineering and Nuclear Operations Service Department will be increased by 60 positions to support plant operations and maintenance. One hundred and ten (110) positions will be added to the Connecticut Yankee and Millstone units to support the existing, day-to-day workload at the plants. To comply with the Nuclear Regulatory Commission maintenance rule, reliability-centered maintenance will be used on selective plant systems at a cost of approximately $5 million, and a system-engineering concept will be adopted to help focus attention on the performance of key plant systems. Eighty plus personnel will be added to support this effort.28

That was Northeast’s intention; to monitor how it worked out, the NRC established its own full-time oversight group at the Millstone site, the Millstone Assessment Panel (MAP). The panel, chaired by James T. Wiggins, Deputy Director of the NRC Division of Reactor Projects, was established to “facilitate a high-level of coordination within the Nuclear Regulatory Commission for the resolution of technical and performance issues.” It was put in place to “review the adequacy of PEP and provide a timely decision to [Northeast] regarding its acceptability to the Nuclear Regulatory Commission.” The MAP established its own list of performance problems and required Northeast to “review the list and briefly respond to the Nuclear Regulatory Commission in writing as to how each of these performance issues is addressed in the PEP.” The list included twenty-three “programmatic concerns” identified in earlier SALP reports and in the Special Review Group Executive Summary issued in April 1992. The first item listed was “proper balance between safety and cost containment.”29 The number of NRC inspectors at Millstone was increased by approximately 50 percent in 1994. In addition, Millstone Two was discussed at eleven of the NRC Senior Management Meetings after June 1991, as a plant with special regulatory concerns. In addition, Northeast was subject to increasing fines from the commission for day-

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to-day violations of operating rules.30 Intense monitoring made it clear that the commission was not convinced that the conflict between safety concerns and cost containment had been resolved at the Millstone plant site.31

Operating Problems at Millstone in 1993 In spite of promises of operational excellence, the spring of 1993 brought a new round of breakdowns. The new approach at Millstone was not working. In early May the Nuclear Regulatory Commission issued a notice of violation (NOV) against Northeast for the harassment and intimidation of a Northeast nuclear supervisor who had raised safety issues. The NRC noted that although company accusations against the employee had been shown to be unfounded, they were not retracted by the company, and had “a chilling effect” on other employees’ willingness to raise safety concerns. The case was of “particular significance” to the commission for several reasons: the issues involved were of industry-wide concern; Northeast did not rectify its mistake in spite of numerous internal and external investigations pointing out the error in the company position; and “officers of the company were either directly participating in discrimination against the employee or were aware of it but failed to act in an effective manner to correct the situation.”32 The commission imposed a $100,000 fine because of “significant management involvement in the violation.”33 Although Northeast stated that it did not agree with the cited violation, it did not contest the citation, and paid the fine.34 In addition to this NOV, the commission issued a SALP report on company operations for the period February 1992 through April 1993. It stated that Millstone Station had “improved marginally,” given that “the self-assessment initiative and action plans in the Performance Enhancement Program were positive steps toward improving performance. However, . . . progress in implementing PEP has not yet produced significant overall performance improvement.”35 At that stage, PEP was no more than a planning exercise. The SALP report also stated that “continuing training program weaknesses were observed at Millstone, particularly in the area of Licensed Operator Requalification Training (LORT) at Unit One. As a result, the Unit One LORT program was rated as unsatisfactory for the second consecutive year. This failure was indicative of inadequate root cause analysis and ineffective corrective action, as well as a noteworthy lack of corporate and site management attention to an identified performance problem.” Nuclear plant operators were not being trained to take on up-

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graded responsibilities while plants were running; the mistake was that Northeast had no training in procedures to follow in developing and evaluating corrective responses: “long-standing performance problems remain in the area of procedural adherence and corrective action effectiveness across the station. Additional management attention to these areas is warranted. Consequently, the area of Safety Assessment / Quality Verification was rated a SALP category 3 [the lowest rating].”36 Subsequent to the period covered by this SALP report, the most significant event in this decade relating to reactor safety began in May and continued until August of 1993: the “442 event.” According to a September 1993 NRC Inspection Report, a Millstone Two work team attempted to stop leakage in a motor-operated valve, labeled 2-CH-442, while the reactor was in operation. This valve closed a piping system that provided reactor coolant, removing heat from the nuclear fuel with steam at 550 degrees Fahrenheit and 2,000 pounds per square inch pressure. To save costs, they attempted to repair the leak while the plant was in operation, in spite of the risk of a major rupture of the valve or the piping system, which could have released steam, endangering personnel and risking damage to the interior of the plant. Rather than shut down the plant for approximately two weeks to do the repair, Northeast drilled into the valve to inject sealant into the gasket and then began “peening,” that is, striking the area with a pneumatic ball-peen hammer to close the hole. The repair succeeded for a short period, but the leakage reappeared. In all, peening was performed approximately thirty times, until finally one of the studs holding the valve cover in place failed, causing the reactor to depressurize and go into forced shutdown.37 In investigation of the outage, the NRC described the stud breakage as having had the potential of causing a Loss of Coolant Accident (LOCA), which would have caused a “decreased margin of safety and (increased) risk of injury to employees.” In fact, the Nuclear Regulatory Commission concluded that Northeast, by attempting to repair the leak multiple times while the plant was in operation, had allowed “errant repair activities to continue over an extended period without intervention by either management or the engineering organization. The fact that these activities continued despite frequent observation by quality service inspections and surveillance personnel is considered to be a breakdown in [the Northeast] quality assurance program.”38 Northeast’s internal reviews of this event were more disquieting. One conclusion was that, in general, the corrective action program was not working, with the peening incident as a prime example.39 The staff of Nuclear Quality and Assessment Services outlined the reasons why the nuclear safety concerns were not identified while repair was underway: although inspectors were involved, they did not focus on the larger safety

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issues and accepted assurances from other departments that the potential for valve failure had been analyzed and found to be low. “These analyses may be acceptable for a personnel safety concern but should not have been accepted for a nuclear safety concern.” The report noted that the department was too “compliance based,” requiring a prespecified level of failure to justify stopping work, rather than making an independent judgment that the entire activity was unsafe. In this case, contract inspectors (i.e., not permanent employees) worried that bringing up safety issues might affect their future employment; other inspectors addressed the potential for failure with the maintenance department but did not discuss it with their own supervisors. Although some of the inspectors involved became convinced that there was a significant safety risk, one contract inspector, while concerned about the safety of the process, volunteered to sign off on the inspection to prevent a confrontation with management.40 And at the same time, according to one published source, before the culminating accident, the plant manager had received a performance commendation for keeping the plant on line during the extended repairs.41 In sum, although an unsafe procedure was undertaken, with great potential for a LOCA, no intervention occurred until the plant went into forced outage. The Nuclear Regulatory Commission did not view this accident at Millstone Two as a one-of-a-kind event. Its next SALP report, issued August 26, 1994, traced what it described as continuing degradation of operational quality, particularly at Millstone Two, but extending to all three plants at Millstone, in spite of new programs and regulatory warnings: Performance at Unit Two indicated significant weaknesses in the areas of plant operations and maintenance. Despite attempts to achieve consistent improvements such as through the Performance Enhancement Program, the Procedure Upgrade Program and other programs, lasting performance improvements at the site have not been achieved in several areas. In fact, performance as measured at Unit Two has significantly degraded as a result of long-standing programmatic and staff performance weaknesses that adversely affected that unit staff’s response to several challenges presented during this period. Several weaknesses in performance, common to all three units . . . included continuing problems with procedure quality and implementation, the informality in several maintenance and engineering programs which contributed to instances of poor performance, and the failure to resolve several long-standing problems at the site.42

The performance results at the three Millstone plants were not good, reflecting this particular CH-442 event but also other less spectacular accidents that caused limited shutdowns. The three plants were in outage a

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substantial part of every year from 1992 to 1994 (see table 3.5). Millstone One was in forced outage for 120 days in 1992 and in scheduled outage for 130 days in 1994. Millstone Two was in scheduled outage for 216 days in 1992, the longest on record; in combined forced and scheduled outage for 55 days, a relatively short time, in 1993; but again for 186 days in 1994. Millstone Three was in forced outage for 84 days in 1992 and in scheduled outage for 99 days in 1993. The longer scheduled outages, beyond normal for refuelings and maintenance, stemmed from equipment replacements, some of which were required as part of industry equipment upgrades—as in the case of the Millstone Two steam generator—but others resulted from additional maintenance required because of “unexpected technical and operating difficulties,” and “weaknesses in work control processes.”43 The Northeast 1994 Annual Report noted that there had been substantial deterioration in its nuclear operations, having achieved only an average capacity factor of 57.6 percent for the five units. The report promised that the nuclear operations would “return to its position as a recognized industry leader . . . and a resulting restoration of regulatory confidence.”44 With this assurance, reengineering was to become the new management process to achieve enhanced efficiency and reduce costs throughout Northeast. The “kickoff” of reengineering in the nuclear organization was in early 1996, with increasingly strict cost containment leading up to implementation. CEO Fox made it clear that not only management but also the Board of Trustees “vigorously” supported this initiative to “downscale, focus and incentivize” Millstone operations.45 The steps to be taken were substantial. The projected annual growth rates of costs for the company, in the range of 4 percent, were to be reengineered to result in a 2 percent decrease in costs. Nuclear engineering and operations now had to achieve reductions in operating and maintenance costs, becoming more stringent over time: overall year-to-year and capital expenditures had to decline by 40 percent over five years.46 The Connecticut DPUC in a decision issued some years later summarized the results of these performance targets. Given the forced shutdowns at all three Millstone Units, the department concluded that the targets constituted a “course of imprudent conduct.” There was a continuing decline in SALP ratings, and PEP was to the point of being forced to fail, due to Northeast’s “undue focus on meeting specific schedule and budget targets.”47 The decision stated, “despite being warned that an excessive focus on budget concerns would ultimately be more costly to the Company than a focus on correcting its performance decline, the Company again opted to sacrifice its nuclear program to financial concerns.”48 The decision described programs that were designed to “reengineer” the company out of its problems as essentially lacking in execution. In the

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commission’s view, Northeast did not take prudent steps in spending on operations and investing in equipment required for stabilizing continuous operations of its plants.49

The Strategy of Northeast and the Board of Trustees In spite of these operational and regulatory problems, management reiterated the primacy of cost containment in the nuclear facilities throughout 1993 to 1996. Nuclear operations were the focus when it came to setting budgeting targets, to be passed down to the plant level; but this time the budget cuts included cuts in the Performance Enhancement Program itself. The second-phase completion report made to the Nuclear Regulatory Commission in 1992 acknowledged that cost-containment programs could have an impact on funds spent on the program: “The total resources for all action plans likely reflect a resource ceiling for the overall effort. As we proceed . . . we expect that continued integration of the various activities will result in our ability to achieve our goal of operational excellence with something less than the level of resources that has been allocated and authorized.”50 The position that PEP was ineffective and costly was reviewed by the Northeast Board of Trustees. When the R. C. Brown consulting firm interviewed six members of the board as to their evaluation of performance at the Millstone plants, it found that “NU Trustees realized that PEP was misdirected and was not sufficient to resolve the most serious issues affecting performance. One Trustee described the situation as Northeast having lost interest in PEP and ‘leaving it in space.’”51 This was after management reviewed the progress of the PEP in several board meetings, with what was described by a board member as “check lists,” with apparently no evaluation of “the effectiveness of the PEP action plans.” R. C. Brown concluded that “the consensus among the Trustees interviewed was that the PEP had been largely unsuccessful.”52 The deterioration of nuclear plant performance was brought to the attention of the board through discussions with two other groups, INPO and the NRC, in 1995. Two highly unusual meetings, one with INPO executives and the other with the NRC executive director, presented the case to the board that nuclear operations constituted a major problem for the company with its regulators. INPO, as industry self-regulator, made a highly critical report of Northeast’s nuclear performance and presented it directly to the Board of Trustees, rather than just to management.53 There was no documented board response. This lack of response was in contrast to the impact that similar INPO reports had elsewhere. (For example, when escalating problems with Philadelphia Electric’s

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Peach Bottom nuclear facilities led to a critical report by INPO and a visit to the board, the chief executive and chief operating officers both resigned.54) In Northeast’s case, no subsequent action was taken by the Board of Trustees. Then there was a highly unusual request from the NRC Executive Director, James Taylor, to meet directly with Northeast’s Board of Trustees, signaling an exceptional escalation of regulatory concern with Northeast’s operations. On March 17, 1995, Mr. Taylor met with the board on what the commission described as “lingering performance problems at the Millstone Nuclear Power Station.” The NRC’s follow-up letter summarized the meeting: The purpose of the meeting was to assure [the NRC that] the Board was cognizant of the seriousness of the concerns and recognized the need for timely improvement in equipment and personnel performance at the Millstone facility, particularly Unit 2. The NRC participants outlined the basis for NRC concerns, including the handling of employee concerns, procedural adherence, corrective-action process effectiveness, competition and communication between units, and historic emphasis on cost savings, as previously documented in the latest Systematic Assessment of Licensee Performance report dated August 26, 1994. The Board of Trustees acknowledged the need for improved performance, assured [the NRC that] adequate financial support [would be provided] for needed improvements, and expressed appreciation for the meeting.55

This visit from NRC’s highest ranked executive once again produced no documented board response; indeed the board showed its loyalty to management by asking questions to Director Taylor that had been written by Chairman Ellis. It did not waver from its support of corporate management on the cost-containment strategy. After a short period, the company’s chief nuclear officer resigned and was replaced by the plant manager at Seabrook; but upper management remained in place. It is most notable that in concurrent discussions of PEP effectiveness, and of Millstone plant operating failures, that the trustees did not openly question management.56

The Financial Success of Cost Containment Northeast continued to show financial gains from cost containment throughout the first half of the 1990s. Northeast pronounced cost containment a success in each of the annual reports it issued over those years. The 1991 Northeast Utilities Annual Report described that year, the twenty-fifth anniversary of the founding of the parent company, as a year “tempered somewhat by the economy and a temporary falloff in our nu-

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clear operations.”57 In addition, operations and maintenance spending was increasing due to operational problems, putting pressure on earnings. A September 1992 Financial Forecast and Review, issued to the investment community, highlighted the PEP as resulting in O&M expenditure increases of approximately $40 million per year.58 But the annual report that year stated that earnings were down, because of a “struggling” New England economy causing reductions in sales of electricity. Then in 1993, revenues increased 12 percent and operating earnings 7 percent; and in 1994 revenues were flat, but with cost control becoming fully effective operating earnings increased another 15 percent (see table 4.4). Earnings per share increased from $2.12 in 1991, fell to $1.60 in 1993 in the aftermath of the cost increases associated with restarts at Millstone, and then increased to $2.30 in 1994 (see table 4.5). In broad perspective, the mid-1990s stage of the competitive response strategy had, at the least, stabilized earnings when economic conditions lagged. The billion-dollar increase in revenues over the five-year period had resulted in $200 million of increased earnings. While this was twice the rate of growth of earnings of the earlier period (compare table 4.4

TABLE 4.4 Northeast Utilities Consolidated Financial Performance, 1991–95 (millions of dollars)

Operating Revenues

1991

1992

1993

1994

1995

2,754

3,217

3,6297

3,643

3,751

674 764

773 828

918 979

832 919

909 967

230 239 377 2,364

274 283 468 2,776

266 321 465 3,158

306 335 541 3,095

289 354 518 3,158

390 191 237

442 250 256

471 292 250

548 281 287

592 299 282

2,760 2,441 5,201

4,942 2,832 7,774

4,638 2,846 7,483

4,303 2,923 7,226

4,022 2,897 6,920

Operating Expenses: Operation – Fuel Other Maintenance Depreciation Taxes Total Operating Expenses Operating Income Interest Charges Income (Cont. Operations) Long- and Short-Term Debt Preferred and Common Equity Total Capitalization

Source: Northeast Utilities, annual reports, various years.

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TABLE 4.5 Northeast Utilities Statistics on Financial Performance 1991

1992

1993

1994

1995

2.12 1.76

2.02 1.76

1.60 1.76

2.30 1.76

2.24 1.76

Book Value per Share ($) Market Price per Share ($)

15.73 235/8

16.24 261/2

17.89 233/4

18.48 215/8

19.08 201/4

Deferred Return on Plants (% of Earnings)

24.7

28.1

37.1

23.8

13.3

Earnings per Common Share ($) Dividends per Share ($)

Source: Northeast Utilities, annual reports, various years.

with table 2.2), earnings per share were still in the $2.00 range and dividends per share stayed at $1.76. But there were important gains: for one, deferred nuclear plant investment was reduced from 25 to 13 percent of earnings. Shareholder value of a common share ended up in 1995 at $20, the same as in 1990, but book value had risen from $16 to $19 per share (compare table 4.5 with table 2.3). Market value still exceeded book value per share at the end of this period. This financial performance is in absolute terms, and an important question is how well Northeast performed relative to other electricity producers and distributors. The most insightful measure of relative performance is the dollar return to investors over what they could have earned elsewhere. Such a measure is termed “economic value” (EV).59 This framework can serve as a basis for estimating the success of the ongoing strategy into the mid-1990s. The company appears to have generated negative EV in some years and positive EV in other years from 1990 through 1995. Overall, in this period, net operating profits after taxes just covered investment costs. But compared to the average EV for the twenty-eight large electric utilities nationwide, Northeast generated slightly greater percentage returns over 1991–95 than other utilities on comparable investments. The strategy maintained better-than-industry parity in earnings (see table 4.6). This better performance, however, followed from a strategy with substantial risk of adverse regulatory action. The Northeast costcontainment strategy had by then incorporated the risk of a regulatorimposed plant shutdown. Although the risk was not advertised widely in public, investors basically failed to bid up the share price as earnings increased in 1993–94, behavior that was consistent with the absorption of increased risk not being worth it.

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TABLE 4.6 Comparison of Northeast Utilities and 28 Large Electric Utilities

Northeast Economic Value ($ millions)

1990

1991

1992

−31

70

−13

Percentage (%)

−0.5

1.2

−0.2

Electric Utility Avg. (%)

NA

−0.8

0.0

1993 64 (adj)

1994

1995

−25

43

0.8 (adj)

−0.3

0.5

8.6

−0.6

0.0

Source: Calculated using Compustat financial data on twenty-nine electric utilities, including Northeast Utilities. Notes: Economic Value as estimated is a variant of Stern Stewart EVA™. “Electric Utility Average” consists of average EV levels for twenty-eight large electric utilities for which Compustat data are available. Financial information for Northeast Utilities for 1993 is adjusted to exclude changes in Generally Accepted Accounting Standards related to deferred taxes that year. Values for Northeast based on unadjusted values would be EV of 1,275, with a percentage of 15. Comparable adjustments are not available for the industry figures.

Strategy and Management Compensation In review of the application of Northeast’s strategy during 1991–94, the first question goes to the status of management: how had this combination of financial returns and regulatory risk affected Northeast’s management? The answer depends in good part, as always, on management incentives to run the company in the interests of customers, employees, investors, and regulators. In all of Northeast’s discussions of strategy, the focus on maintaining its customer base in the face of some actual and much potential competition indicates that the interests of customers was a concern. But there appears to have been a central concern for the effects that reduced sales would have on earnings and ultimately on returns to investors. Incentives in the compensation package—the determinants of salary and bonuses (plus stock options) of senior management— were derived from earnings and returns to investors. Northeast’s “Executive Incentive Compensation Program” reached down from the CEO to thirty executives, inclusive of division vice presidents; a bonus system, the “Performance Reward Plan,” applied to five thousand employees throughout the company. The priority criteria for payout any year were “shareholder returns” and “cost of service” containment targets. Only if plant outages increased costs, or reduced revenues, would there have been an adverse affect on executive compensation. Between 1991 and 1994, neither the deteriorating performance of the nuclear plants nor the negative feedback on safety affected executive

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compensation triggers. Such a result was noted in the R. C. Brown report.60 For plant-level managers, goals for plant capacity factors were added to existing cost-control goals (but only in the mid-1990s). The weights given the new measures did not exceed 15 percent, and the total dollars available in the plan were determined by financial goals. As the Brown study concluded, “While both programs [senior management and other employee incentives] have changed and evolved over time, in no iteration were the programs designed to sufficiently tie incentive rewards to addressing the types of concerns which, in the aggregate, have led to the current forced outages.”61 The resulting compensation for top executives is shown in table 4.7. The chairman (Mr. Ellis) before his retirement and the CEO (Mr. Fox) realized reductions in total compensation in the 10 percent range in 1992, the worst operational year. Compensation packages recovered with increases in the range of 30 percent in 1993. The two top operating executives, Messrs. Fox and Busch, realized increases of 37 percent in 1994. In granting these awards the Board of Trustees in effect agreed that performance goals had been achieved, even as the safety and operational results in nuclear had deteriorated. In its 1996 analysis of Northeast management’s conduct, R. C. Brown and Associates reviewed the incentive programs for middle and lower management. Their report concluded that “the nature of the goals, the weightings attributed to them, and the availability of relatively large incentive awards for management and supervisory personnel contributed to the perceptions within the nuclear organization that executive and senior managers placed greater importance on production and cost issues than on regulatory compliance.”62 That is, incentive bonuses for plant-level management mirrored the financial priorities of the company, similar in many ways to those in the executive compensation plans. For example, the “Performance Reward Plan” for middle managers in 1993 included bonuses based 34 percent on meeting O&M budget targets, capacity-factor targets, and PEP deliverables. Safety goals accounted for 33 percent and corporate earning goals accounted for 33 percent; but actual payouts that year were almost entirely for achieving earnings goals.63 By 1995 the program had been revised as the “Nuclear Performance Incentives Program.” NPIP had nuclear O&M budget constraints, plant-operating capacity factors, and PEP deliverables accounting for 40 percent, while “operational excellence” accounted for 50 percent. Year-end payouts were entirely for nuclear O&M cost reductions.64 Plant managers could count on bonuses for achieving plant operations that stayed within budget reduction targets, while avoiding forced outage remained a secondary consideration. Budget targets were widely used elsewhere as compensation incentives

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TABLE 4.7 Total Compensation of Senior Executives of Northeast Utilities, 1991–97 (thousands of dollars)

B. M. Fox R. W. Busch W. B. Ellis J. F. Opeka

1991

1992

1993

1994

1995

1996

1997

586.1 292.6 764.5 354.3

505.2 281.5 649.9 309.4

727.7 373.9 769.3 382.4

973.6 568.0 777.0 407.9

934.9 568.1 530.0 449.6

629.2 3,000.6 – –

1,630.9 – – –

Source: Proxy statements of Northeast Utilities, SEC Schedule 14A; inclusive of salary, bonus, restructured stock awards, long-term incentive program, and all other compensation. Notes: W. B. Ellis retired before the end of this period. The case of B. M. Fox, for 1997 compensation includes payment on retirement, fees for contract consulting, previous year bonus, and excess retirement and tax reimbursement on his retirement annuity. In the case of R. W. Busch for 1996 includes payments pursuant to terms of his separation agreement.

in period, with what now has been recognized as adverse results. Those whose compensation was based on reaching specific targets, with priority weight, had a tendency to move off efficient operations in order to attain the pre-set number for sales, earnings, or returns on assets.65 As documented by Michael Jensen, “[M]anagers have information that is important in setting their budget targets. . . . Once a budget-target reward system is in place managers have no interest in seeing such information accurately incorporated.”66 In the case of Northeast, by centering targets on the level of maintenance and production costs, in a list of contradictory goals, the company made the two worst errors. Jensen’s rule of thumb is “If it is a performance measure and it’s a ratio, it’s wrong.”67 Using a ratio as a measure blurs the incentives by not specifying whether one should attack the numerator or the denominator. Northeast’s strategy called for reductions in electricity costs in cents per kWh, by emphasizing deep cuts in maintenance expenses in high overhead plants rather than looking for activities leading to increased production. In Northeast’s case, the first worst error was to emphasize current dollar O&M reductions. Plant and site managers were faced with the dilemma of decreasing O&M outlays (“cents”) rather than increasing outlays to reduce the probability of forced outage (“kWh”). For the most part the response met short-run cash targets and would reduce kWh only in future years. The second worst error in Jensen’s view is to mandate multiple performance measures without specifying trade-offs among them. To list “operational excellence” at one-third weight and “cost containment” also at one-third weight seems clear enough, but cost containment had no effect on operational perfor-

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mance until years later. Managers could take the short-term approach, with no impact on bonuses this year, and with the threat of a negative impact off sometime in the future.68

Another Look at Alternative Strategies The question in 1993–95 for the competitive response strategy, which was how to generate returns while the company was mired in plant outages, was the same as in 1991. Was it better than the most attractive alternative? The comparison with California’s Diablo Canyon nuclear facility is appropriate. PG&E’s Diablo Canyon, similar to Millstone Three in age and technology, developed the highest ratings in operational and safety performance under an alternative strategy. PG&E management was willing to spend whatever was required to meet and even exceed safety and reliability standards. As a result, Diablo Canyon reached capacity factors in excess of 80 percent for both units in the period when Millstone capacity factors were at half that level (see table 4.8). PG&E’s 1998 Annual Report noted, “Diablo Canyon Power Plant retained the top position in its industry, the only nuclear power plant to have continually received a No. 1 rating, the highest granted by the Institute for Nuclear Power Operations. . . . Diablo Canyon’s Unit One set a world record in 1998 among comparable units for continuous net generation.69 As a result of high-capacity factors, the Diablo Canyon units generated high earnings for its parent corporation, in some months producing half of PG&E’s total corporate earnings. Diablo production benefited from what turned out to be generous terms in its pricing agreement with the California Public Utilities Commission; these terms motivated operational and maintenance expenditures, not cuts, leading to additional production and earnings (again, as in table 4.8). A strategy similar to that at Diablo Canyon for Northeast’s operations and maintenance expenditures would have led Millstone Three, a comparably sized and engineered plant, surely to perform better than it did. We cannot know how much better, but comparable data is revealing for Diablo One and Two and for Millstone Three, with respect to costs (cents/kWh), operating rates (%), and operating and maintenance cost outlays.70 Although the data do not allow for extensive modeling and prediction, a simple trend analysis provides some insight. With costs per kWh regressed on those three variables, only capacity factor is statistically significant, which suggests that operating and maintenance outlays that support an increased capacity factor result in at least comparable, and at times lower, per kWh generating costs. Even without modeling, it is clear that if Northeast had spent what

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TABLE 4.8 Diablo Canyon Power Plant Operations and Earnings

1989 1990 1991 1992 1993 1994 1995 1996

Combined Capacity Factor

Net Generation MM kWh

EPS ($/share)

Percent of Corporate EPS

84% 86% 80% 88% 89% 81% 86% 88%

15,812 16,274 15,073 16,638 16,816 15,265 16,269 16,720

0.45 0.67 0.59 0.99 1.11 1.04 1.16 1.18

24% 32% 26% 38% 48% 47% 39% 67%

Source: PG&E, operating and statistical reports, various years. EPS = earnings per common share.

was required to stay in the 85 percent capacity utilization range in 1992, if not before, then safety problems would have been mitigated and production rates would have increased. On the bottom line, Millstone nuclear power costs would have become more competitive over the long run. Earnings would have been lower in the immediate years because of increases in operating, maintenance, and (possibly) capital outlays at Millstone, but these increased expenditures would have been made up by higher revenues and earnings, due to increased production, in the future. Then, what can we say about the continuation of management’s strategy to the mid-1990s? The company-wide cost-containment strategy was still in place, based on rhetoric that competition in power generation, resulting in the entry of others with lower-cost power, would dislodge Northeast’s position as the premier power provider in southern New England. This strategy had to be modified for NRC requirements that some O&M and capital expenditures had to be injected back into the poorly performing Millstone plants by 1992. Management had to supplement cost containment at that time for PEP, but it then turned to reengineering in nuclear to extend cost cutting. Plant performance fell to spectacular lows with the CCH-442 Accident at Millstone Two, the result of decisions to repair faulty equipment while keeping the plant running to reduce costs. The proposition that PEP signaled a turnaround was denied when it too was cost contained by reengineering. The well-known alternative, the Diablo Canyon strategy, involved reduced present earnings for increased future earnings. There was very little in Northeast’s compensation plans supporting that trade-off. It was not taken.

Five Northeast Strategy and Regulatory Shutdown of the Millstone Plants

The Nuclear Regulatory Commission did not regain confidence in Northeast after the PSNH merger and PEP agreement, given that PEP produced no real evidence of a turnaround in Millstone plant performance. The “peening” event at Millstone Two added to the view that operations were at the margin in the trade-off of nuclear safety for cost containment. The commission’s position was known by the management of Northeast’s nuclear group, its senior corporate management, and its Board of Trustees. Northeast failed in numerous conferences and agreements to resolve the problems that it had created with its regulators. In 1996, the Nuclear Regulatory Commission designated Northeast a Level Three company on the Watch List, and ordered the company not to restart the Millstone plants until they had been reconstructed and relicensed. The company was out of production at Millstone, losing 40 percent of its generation capacity, and had to spend more than a billion dollars in qualifying two of the plants for relicensing. It divested its generating facilities, and retail operations were put up for sale. The final question is, why did management push its strategy over the edge?

Failing Operations at Millstone A series of safety-related events set the stage for this final crisis in plant operations. In August 1995, an engineer at Northeast petitioned the NRC to shut down Millstone One because of violations of its license requirements. The petition alleged that in its refueling practices, management at Millstone One violated its Updated Final Safety Analysis Report (UFSAR) by engaging in a “full-core offload,”1 which removed the spent nuclear fuel from the reactor for transport to a storage pool in one sequence instead of in three separate sequences, as specified in the plant design.2 Although the spent-fuel rods no longer had sufficient energy to produce steam and generate electricity, they were radioactive and at high temperatures so that they were quite hazardous. Mistakes in handling these materials could have had severe safety consequences; handling

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them in one offload, “out of design,” was less costly but had to involve increased risk of accidental radiation exposure. Because full-core unloading had not been incorporated into the design basis for the original license, the procedure had not undergone engineering testing and simulation; in that sense, conceptualization of the dynamics of this operation had not taken place. The petition alleged that the Nuclear Regulatory Commission should have prohibited the full-core offload from inception, rather than having tolerated it for a number of years. In response to the petition, the Nuclear Regulatory Commission sent a notice to Northeast stating that the offloads may have constituted a “violation of license requirements” and that it was initiating an investigation by its Office of Inspector General (OIG) to determine whether the plant’s operating license should be “suspended, modified, or revoked, or other enforcement action taken.” The notice, known as a 10CFR 50.54(f) letter, required Northeast to respond by describing actions it would take to ensure that Millstone One would be in compliance with its license before it restarted.3 Within two days of that notice, the commission established another review group to evaluate Northeast’s handling of the “high volume of [Millstone] employee concerns and allegations.” In its notice it stated, “The NRC has conducted many inspections and investigations which have substantiated many employee concerns and allegations. The licensee has been cited for violations and escalated enforcement has been taken. Notwithstanding these NRC actions, the licensee has not been effective in handling many employee concerns nor implementing effective corrective action for problems identified.”4 The OIG report on full-core offloading at Millstone One, dated December 21, 1995, was entitled “NRC Failure to Adequately Regulate— Millstone One.” The investigation determined that NRC resident inspectors at the Millstone site were aware of the practice of full-core offloading, but did not know the design basis well enough to realize that the practice was contrary to the facility’s license. The investigation also determined that there had been no analysis of the heat removal capacity of the Millstone One spent-fuel pool cooling system under the conditions of a full-core offload. Thus, no specific Northeast or NRC staff determination had been made concerning the safety of the practice and its consistency with the operational design of this facility.5 But the practice had been subject to repeated warnings by the Northeast employee who eventually brought the petition to the commission. To correct this ongoing violation, Northeast proposed a design amendment in July 1995, supplemented in September 1995, which was approved in November 1995, many years and refuelings after the practice had become a regular part of operations at Millstone One.6

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In January 1996, the Nuclear Regulatory Commission placed the three plants at Millstone station in Category Two on the Watch List, which allowed these facilities to continue to operate, but under heightened regulatory scrutiny.7 Shortly after notification, the commission issued another combined Inspection and Notice of Violation. Although it noted that there had been some positive response to the commission’s increasing oversight, the NOV stated that significant violations remained.8 On January 30, 1996, management received an internally commissioned Employee Concerns Assessment Report, a strongly worded statement on its poor working relations with employees, based on hundreds of private interviews and reviews of documents: Nuclear Division management . . . has not implemented past recommendations in a coordinated or effective manner. This, coupled with a simultaneous lack of commitment and accountability in implementing corrective action, has resulted in continuous failure to resolve issues. Compounding the situation has been the general inability on the part of many management individuals to frankly admit when they are wrong. . . . The effectiveness of the NSCP [Nuclear Safety Concerns Program] has been historically hampered by a lack of executive management support. A similar absence of support in line management has resulted in a high backlog of unresolved issues. Simply stated, the NSCP lacks sufficient resources and authority to properly process and resolve employee concerns in a timely manner.9

Northeast’s management response to the offload crisis, Watch List designation, the employee concerns report, and the NOVs was to treat them as brush fires to be put out effectively, but quietly, one by one. Its focus still centered on budget control at Millstone. A press release on January 11, 1996, noted that one hundred nuclear employees were being separated from the company as part of a total of a two hundred and fifty employee reduction in nuclear operations (with the rest to leave later by voluntary early retirement). Although he asserted the importance of safety, Robert Busch, the vice president for power generation, was quoted in the press release as stating, “We must streamline our organization to meet the competitive challenges we face in the future.”10 In January, Northeast fully extended reengineering into its nuclear operations as “Core Process Reengineering.” It created a special task force of sixty employees, undertook a “major overhaul of how we do business so that we can be successful today and tomorrow” to become the low-cost provider that was “innovative, flexible, and customer responsive in a vibrant and vital environment.”11 Northeast completed its internal response to the NRC notice on fullcore offloading at Millstone One in February 1996. Known as the “ACR 7007 Report,” it presented a revealing list of dysfunctional conditions.

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The report noted that Millstone One had never had a complete Final Safety Analysis Report, it had not maintained the level of the partial FSAR that it did have in place, and it had a lack of effective corrective action to maintain compliance with the flawed FSAR.12 The summary list of specific “fundamental causes” was as follows: • •

• •

The original 1986–87 FSAR contained errors and omissions. The administrative control program did not fully address regulatory requirements. Assuming that the original FSAR was accurate, verbatim compliance with previous and current administrative programs would not have maintained an accurate FSAR. Corrective actions did not fully address the adequacy of administrative programs for meeting regulatory requirements. NU did not fully implement its administrative programs [nor] did [it] treat the FSAR as a document that was required to be accurate. Internal correspondence and events involving the design basis from 1985 through 1996 show a pattern of information communicated to NU management [that] consistently identified weaknesses and risks associated with the UFSAR [updated report] and design basis. NU management made commitments, on the docket, to correct these deficiencies. These actions were ineffective, partially implemented, or not done.13

Due to the nature of these conditions, the report concluded that the potential existed for similar conditions at the other Millstone units. The team could not ascertain the full extent of this potential, however, without investigations similar to the 10 CFR 50.54(f) review then currently in progress for Millstone One.14 The report concluded with a list of adverse conditions discovered in the operations at Millstone One revealed by the investigation: There is an organizational tendency to focus narrowly on the technical aspects of issues and their technical resolution. This lack of a questioning attitude inhibits the identification of root causes, generic implications, and the corrective actions to prevent a class of recurrent issues. While there is a strong emphasis on safety as a stated objective, the organization does not consistently recognize or emphasize the collective set of administrative and technical processes that demonstrate and assure that objective is met. Task completion and scheduling compliance are primary [but] there is an absence of performance or success criteria.”15

Although the ACR 7007 Report was intended to be confidential and remain internal to Northeast, on March 7, 1996, less than two weeks after the report’s completion, the company learned that the Nuclear Regulatory Commission had received a copy from an unknown source. The commission’s letter to Northeast stated, “NRC has obtained a copy of an internal Northeast Utilities document”; it described the document and

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quoted some of the points listed above. The letter required Northeast to expand its review of plant conformation to FSAR to cover Millstone Two as well, and promised a separate letter on Millstone Three. Finally, the commission stated that a copy of the letter and the required response from Northeast would be made public; it would make the ACR 7007 report public on March 15 unless Northeast provided “sufficient basis to withhold the report.”16 Northeast, undoubtedly seeing no alternative, the next day released the report.17 In addition, given its concern with deviations from FSAR, the NRC wrote two almost identical letters addressing both Millstone Two and Millstone Three. The first letter required Northeast to expand to Millstone Two its review of plant conformation to FSAR, and submit it no later than seven days prior to any start of that facility. The second letter gave Northeast thirty days to conduct a similar review for Millstone Three, which at that point was still operating.18 Shutdowns of all three Millstone plants were shortly in place. Millstone One had not been allowed to restart from its late 1995 refueling, pending compliance with the UFSAR and with requirements for operator training. Millstone Two had experienced significant performance problems in restarting after a 1994 refueling, which extended its forced outage for ten months. It finally restarted in August 1995, only to undergo a failed systems outage in December 1995 that kept it out of service through February 1996. After a brief restart, it was removed from service again on February 20 because of operating problems, at which point the NRC prevented any restart of Millstone Two until the FSAR review of the plant was complete.19 In March 1996, Northeast began the review of Millstone Three, required by the commission’s March 7 letter. On March 30, 1996, Northeast had to shut down Millstone Three after finding that containment isolation valves for the auxiliary feedwater turbine-driven pump were inoperable because the valves did not meet license requirements.20 Then, on April 4, 1996, Northeast issued the preliminary results of its investigation of Millstone Three, and concluded, “We have identified programmatic issues and design deficiencies at Millstone Three that are similar in nature to those at Millstone One and Two.” The report stated that “design and configuration control deficiencies at Millstone Unit Three have been identified, and have been evaluated with regard to plant operability, the existence of [previously] reviewed safety questions, and [lack of] reportability.” The commission, in response, again required Northeast to describe actions to be taken to identify deficiencies and corrective actions to eliminate them from plant safety.21 In its follow-up letter, the commission reiterated what Northeast would have to do to demonstrate the effectiveness of its corrective ac-

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tions at Millstone Three before restart would be authorized. The letter noted that recent company safety inspections had determined that the bearing load of the concrete under the Millstone Three containment basin was suspect. In more strident language the commission reiterated, “Because we are concerned regarding the long-term safety implications of this concrete condition and the newly identified discrepancy in the bearing load, we request that you respond to this letter and the enclosed inspection report within 45 days of receipt.”22 In April and May of that year a new special inspection team from the NRC Office of Nuclear Reactor Regulation investigated conditions at both Millstone Two and Millstone Three. The team report provides a graphic depiction of operating conditions at these two plants, not only in minute detail but also in terms of overall plant performance. The detail is interesting for the depiction it provides of day-to-day conditions in these two plants. The team found that in Millstone Three the auxiliary feed water discharge piping was tested by instructing operators to close the discharge valve during startup, creating a plant operating condition that was in conflict with the design specification for safe operation. When Millstone Three discharge valves for the service water booster pump did not meet fire protection requirements, the company response was to install a “jumper” around the valves. This was later reversed, but in the process, the jumper was incorrectly dissembled, disabling the automatic start on the pumps on the discharge valves. In Millstone Two, the hydrogen monitoring system isolation valves lacked the ability to open if a single electrical connector failed; this was corrected by again directing operators to install “jumpers.” The inspection team found that in these cases “safety evaluations . . . were too narrowly focused and did not comprehensively evaluate the consequences of the changes on the operational impact of having in place long-standing temporary measures. In each of these instances the fundamental design issue remained uncorrected and additional burdens were placed on operators to compensate for design deficiencies.”23 In its overall review of conditions, the inspection team found fault with the process of resolving safety issues at both Millstone Two and Millstone Three “similar to those identified at Millstone One as had been documented in the Event Response Team Report dated February 22, 1996.” As noted previously, the earlier condition report had described the process of problem-solving as having very narrow focus and a lack of a questioning approach. This report again described “the general lack of an ‘effective corrective action process,’” and found numerous important instances in which “degraded and nonconforming conditions were not properly corrected, line management did not respond to findings from their own quality assurance organization, and the root causes and pro-

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grammatic implications of identified issues were not addressed in a timely fashion.”24 In the midst of these reviews of Millstone operations, on May 10, 1996, M. D. Quinn of the Millstone staff issued a closeout report on the Performance Enhancement Program. The report concluded that “some action plans were more successful in achieving desired results than others” but “given the current status of the nuclear program at Northeast it is clear that the PEP was not successful in its intended goal of high level nuclear group performance.”25 PEP had delivered “process and event evaluation tools” to apply to faults in plant operations, but had not developed solutions to these faults. PEP developed a tracking system for faults and design manual updates, and it improved the standardization of program manuals in erosion / corrosion, motor-operated valves, and electrical equipment qualification. But these completed items were all paper projects, and generally did not move on to generate action programs to correct systemic faults in actual operations. PEP was originally expected to cost $136 million over the 1992–96 period, but during the annual budget containment exercises it was reduced to $106 million, and actual expenditures were $97 million.26 One could infer that PEP was “cost-contained” by one-third and “downgraded” to paper projects. While Millstone Three was offline and various inspections and reviews were ongoing, it had been found that the containment coolant recirculation system was not adequately designed for loads required by the accident control systems. The problem had existed through the life of the plant, but had not been previously recognized.27 Northeast completed a root cause investigation in July 1996. Although such investigations were ordinarily for single faults, in this case Northeast looked at the complete history that had led to “loss of confidence” in the Millstone Three design. The causes went far back to the reduction of engineering support, as part of cost containment at the start in the 1980s, and to the decrease in FSAR reviews after the elimination of both engineering supervisor and manager positions. The review summarized the findings in a two-page flowchart detailing steps taken to reveal the need for the shutdown (figure 5.1). The key finding was that operating in conformance with the FSAR had not been a company requirement.28 The downtime of the three plants together in planned and forced outage in 1995 and 1996 is depicted in figure 5.2.29 Millstone One’s planned outages exceeded two months in 1995 for the second straight year, and forced outages lasted eighteen days in 1995 and the entire year in 1996. Millstone Two was down six months in planned outage and one month in forced outage in 1995, and then down ten months in forced outage in 1996. Millstone Three, after a normal refueling period of two months in

EVENTS & CAUSAL FACTOR CHART

B

S/U Program Phase I, II,& III to FSAR

Unit FSAR submitted to NRC 10/82

A

SER issues stating facility as described in FSAR is acceptable & meets Standard Review Plan SER issued 11/85

INPO points out Millstone Units not complying with FSAR

Friday, June 21, 1996

Verified Test Program satisfied Technical Specifications

U-1 receives 50.54F Letter 12/13/95

(See page 2)

S/U Program/ fuel loaded

All Millstone Units placed on Watch List 1/30/96

Unit Commercial Operation 4/23/86

U-1 Performs Root Cause Analysis-ACR 7007 Generic implication of culture/ resources, etc, to MP3 2/22/96

SW to DG fouling Service Wtr troubles July 1991

U-3 Shutdown due to AFW 3/30/96

NRC notices performance slipping.

U3 told to furnish additional information prior to restart 4/4/96

SLCRS determined not to meet design requirements Major Outage 10/92

A

NRC Inspection ReportGeneric implication of ACR 7007 applies to MP3 4/4/96

Figure 5.1a. Events and Causal Factor Chart, Prepared by Northeast Utilities as Part of Root Cause Investigation. Page 1. Source: NU, Root Cause Investigation, Revision 1, “Millstone Unit 3 Loss of Confidence in the MP-3 Configuration and Current Licensing Basis,” ACR 13302, July 1, 1996, p. 1. CT DPUC Docket 96-10-060, Responses to Interrogatories, Box 78508086.

EVENTS & CAUSAL FACTOR CHART

Engineering understaffed after S/U

Friday, June 21, 1996 Management did not hold organization accountable to FSAR

PCDRs not closed in a timely manner after implementation. Makes FSAR description inaccurate

Did not train Plant Engineers on importance of FSAR - PDCE concerns (Issues 2 & 8)

Temporary Modifications left in place since S/U due to lack of resources/ priorities. (Issue 1)

Startup Testing accepted if Technical Specifications could be met - items added to backlog if not completely matching FSAR/ design

Unit 3 starts up with large backlog (Issue 5)

Dotted lines used to indicate feedback. The result feeds back to strengthen the perception behind the main causal factor.

Some FSAR changes did not receive 50.59 (Issue 9)

Abandoned Systems not removed from FSAR if PDCR not done (50.59 not completed)

FSAR not considered a formal requirement which must be met.

Systems not functioning are bypassed/ procedurally modified w/o 50.59 even though described in FSAR (Issue 4)

Approach fix via operating procedures such as single failure of SW to RSS Hx vs. design changes

B (See page 1) Page 2

Figure 5.1b. Events and Causal Factor Chart, Prepared by Northeast Utilities as Part of Root Cause Investigation. Page 2. Source: NU, Root Cause Investigation, Revision 1, “Millstone Unit 3 Loss of Confidence in the MP-3 Configuration and Current Licensing Basis,” ACR 13302, July 1, 1996, p. 2. CT DPUC Docket 96-10-060, Responses to Interrogatories, Box 78508086.

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1995, went down in forced outage for nine months in 1996. There were less than three months in which even one plant was operating in 1996. A simple trend analysis of plant online performance shows extensive deterioration through the entire period from 1986 to 1996. For each of the Millstone plants, the hours spent in operation equal annual hours minus scheduled and unscheduled outage hours. When hours in operation Ot are regressed on a constant and a time trend for each year, from the ten years of data for each plant, the time trend coefficient is negative for all three plants, indicating that hours online were declining systematically.30 For Millstone One the hours online declined from 1986 to 1996 at a rate of 4.4 percent per year, for Millstone Two at a rate of 3.8 percent per year, and for Millstone Three at a rate of 2.5 percent per year. These declines in plant performance should have been known by plant management but also by the strategists in senior management and on the Board of Trustees.

Shutdown at the Millstone Site The downgrade of the Millstone plants to the NRC Watch List Category Three and the NRC-required shutdown came in two steps, first a staff recommendation, and second a commissioner-level further downgrade. On June 21, 1996, the NRC staff recommended continuation of the Category Two Watch List rating for the Millstone Station, noting that

100 Millstone 1 Millstone 2

Percentage of Time

80

Millstone 3

60

40

20

0

1985

1986

1987 1988

1989

1990 1991

Year

Figure 5.2. Scheduled and Forced Outages. Source: See table 3.5.

1992

1993

1994

1995

1996

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the three Millstone plants had “weaknesses that warrant increased NRC attention until the licensee demonstrated a period of improved performance.”31 James Taylor, the NRC executive director, stated that the Nuclear Regulatory Commission’s “level of involvement in assessing Millstone activities has heightened over the past nine months. Each unit has been assigned a separate senior resident NRC inspector with a senior NRC manager placed in charge of overseeing Millstone station activities.”32 But this had not led to a “sustained level of performance improvement”; rather, there was no discernable improvement even after the NRC expressed concerns with Millstone One core offloading practices, and after an internal audit was “highly critical of the integrity of Millstone One licensing and design basis.”33 Further NRC inspections disclosed significant problems with license documentation—the “design basis” for operational safety—for all three plants. Director Taylor could not report any progress in meeting NRC requirements for improved Millstone performance. In their meeting on June 28, 1996, the commissioners voted to downgrade all three plants to Watch List Category Three, so that explicit approval by the commissioners was necessary before any of the three facilities could resume operations. As defined by commission rules of practice, plants in Category Three “have been identified as having significant weaknesses that warrant maintaining the plant in a shutdown condition until the licensee can demonstrate that adequate programs have been established and implemented to ensure substantial improvement.”34 The NRC apparently saw no alternative to Watch List Level Three designation and went to shutdown in order to generate an effective response from the company.

Increasing Public Concern In the midst of these operational and regulatory actions, the Northeast “problem” became a major public concern. It had first catapulted into public attention with a cover story in Time magazine on March 4, 1996. Time revisited the treatment of whistle-blowers at Northeast and castigated the Nuclear Regulatory Commission for lack of response to violations at Millstone and other facilities. One Northeast engineer was quoted as follows, “I believe in nuclear power, but after seeing the NRC in action, I’m convinced a serious accident is not just likely but inevitable. This is a dangerous road, they’re asleep at the wheel, and I’m road kill.” The article described in graphic terms the three-year battle of nuclear engineers at Millstone to inform first Northeast and then the Nuclear Regulatory Commission of full core offload violations at Mill-

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stone One. Time’s coverage of the “peening” event at Millstone Two was particularly colorful: “If the system [CH-442 valve] failed, the pool could boil, turning the plant into a lethal sauna filled with clouds of radioactive steam,” which could end by “releasing massive amounts of radiation and rendering hundreds of square miles uninhabitable.”35 Whether accurate or not, the perception created by Time was that Northeast was operating nuclear plants at Millstone Point beyond the margin of safety and the NRC should require it to shut down. The chair of the commission, Shirley Ann Jackson, had just been appointed to her position by President Clinton in July of 1995, with the press report that “NRC Chairwoman Jackson is trying to prove her commitment to safety—and reform an inert bureaucracy.” She was quoted by Time as saying, “The ball got dropped. Here’s what I’m saying now: The ball will not get dropped again.”36 It was clear from Ms. Jackson’s position that the Nuclear Regulatory Commission was under media pressure and not likely to simply add to its long series of warnings to Northeast of Watch List and Category Three designations without taking action. The Nuclear Regulatory Commission’s oversight of nuclear facilities was the subject of public debate as much as was the safety of Millstone plant operations.37 Whether there had been a shift to a harder line in enforcement under Chairman Jackson was debated at that time. Some argued that the commission had had been lax in its prior oversight, leaving too much to the discretion of corporate managers of nuclear facilities. Others argued that the commission overreacted when it responded to the problems at Millstone.38 Without entering the debate as to whether the Nuclear Regulatory Commission’s shutdown of Millstone was appropriate, we note that adverse reactions to Northeast’s performance were building in other political quarters. The Connecticut State Assembly initiated hearings before its Energy and Public Utilities Committee. The committee asked CEO Bernard Fox to respond to a series of requests and questions, including “how Northeast Utilities treats whistle-blowers and who’s going to pay for the replacement power as a result of shutdowns at the Millstone complex, where all three power plants are on the Nuclear Regulatory Commission’s ‘watch list’ of troubled plants.”39 Questions from the committee also included, “What kind of remedies do you plan to implement that will help repair the damage that has been done to NU’s credibility and re-establish a high level of public trust that was once enjoyed by the company?”40 The legislators also asked Northeast if there had ever been an attempt to mislead public officials, regulators, or employees, regarding the operation of Northeast Utilities nuclear facilities.41 Northeast provided thirty-eight pages of responses to the Assembly committee and Mr. Fox assured the legislators that management “had

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never attempted to intentionally mislead public officials, regulators, our employees, or our customers” and that Northeast did “not expect to recover any costs from ratepayers if we have failed to meet industry standards. This includes the cost of replacement power while our nuclear units are not operating, as well as costs incurred due to any sanctions imposed by the NRC.”42 At further Connecticut State Assembly hearings in April 1996, Northeast offered testimony from three witnesses, Messrs Bernard Fox, Robert Busch, and Ted Feigenbaum, the recently appointed director of Millstone. The company witnesses brought a consistent message to the hearings, to the effect that lack of conformity to regulation had to be distinguished from unsafe conditions. Mr. Fox said, “The first thing to recognize, and let me emphatically underscore this, is that Millstone Station is safe. . . . Although in my view these plants are clearly safe, at the same time they are inadequate, vis-à-vis the performance of the industry as it has improved over the past number of years.” Mr. Busch added, “it may be that over the years we operated outside of that particular regulation. But once again, this is a situation where because we were outside of the regulation, doesn’t mean necessarily the situation was unsafe.” Finally, in the same hearings, Mr. Feigenbaum said, “[A]s to the design of nuclear power plants, it is a belt and suspenders kind of an approach. There are thousands upon thousands of requirements and regulations. And when you deviate, or non-conform from a particular requirement, it does not make the units unsafe. But it is something that needs to be straightened out and fully evaluated, which we did subsequently.” All three stated that the full-core offloading never threatened to raise the temperature to dangerous levels in the cooling pools at Millstone One.43 What is so remarkable about the questions and Northeast’s corporate position is that the discussion was in many ways too limited: the risk incurred by Northeast in operating outside license conditions was not simply the extreme risk of catastrophic plant failure. A more likely adverse outcome was that pushing regulation to the limit could result in regulatory shutdown, which would pose serious production and financial losses for employees, shareholders, and customers. The trade-off inherent in the “extended risk” strategy was that of achieving cost containment by incurring a high probability that the NRC would delicense Millstone. The relationship between safety, the Watch List criteria and the license to operate was never addressed by management in the hearings. The company statements on strategic emphasis on budgeting were less declarative. Mr. Fox was asked if he agreed with statements in the ACR 7007 report that budgetary considerations prevented the plant staff from maintaining an accurate UFSAR. His response was less than clear: “I know that there’s been a lot of discussion about budget issues at Millstone Station or in the nuclear organization, and that that’s a matter that

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we’re working hard to be sure the people understand where we are, by way of budgetary matters, and where we’ve been.”44 The Northeast witnesses were immediately followed by Paul Blanch, a nuclear engineer who had spent twenty-one years at Northeast after service in the U.S. nuclear navy. His testimony was scathing, contradicting the Northeast executives both as to the risks taken and the harassment of employees bringing safety concerns to management. He stated that Northeast had not evaluated the safety implications of procedures prior to advocating them in plant operations, that he knew that storage pool temperatures had exceeded safe levels, and that Northeast management was knowingly understating the risks they had taken in the unauthorized offloading of fuel in Millstone One.45 The implications of (1) full-core offloading of fuel at Millstone One, (2) the incident with the leaking CH-442 valve in Millstone Two, and (3) the malfunction of the secondary cooling system in Millstone Three were that the plants lacked systems for containing faulty procedures and fixing faulty equipment. The repetitive nature of these accident events implied that there was no lesson learned across the plants for problem solving. The public discussion of these conditions suggested that management had one version and certain plant employees, along with the NRC, had another.46 A Boston Globe article discussed the emerging competitive electric power market, noting that ten to twenty-five of the country’s nuclear facilities were potentially vulnerable to price competition, and that New England plants were particularly at risk, given their high power costs. “In all, an analyst for Massachusetts Attorney General Scott Harshbarger found that seven of the region’s eight nuclear reactors would lose money if competition drives electric rates as low as some expect.”47 The article focused on the fear that some had of “Valunuke, . . . the nuclear equivalent of ValuJet, the discount airline grounded for maintenance deficiencies after a fatal crash in the Florida Everglades last [the previous] May. . . . [O]wners of hard-pressed nuclear plants could be tempted to take cost-cutting steps like the botched 1993 repair job at Millstone Two.” The Globe article described Northeast’s Millstone in bleak terms: “Once considered a showcase operation, the three-reactor complex at Millstone now is one of the most troubled in the country, closed since March because of literally thousands of problems that federal regulators traced to cost-cutting efforts.”48

The Role of the Board in the Northeast Utilities Collapse The shutdown at Millstone had an immediate impact on the company’s financial condition: operating income fell by $283 million (48 percent); and net income, $39 million in 1996, was negative $130 million in 1997

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(see table 5.1). The price of common shares fell to thirteen dollars in 1996 from nineteen dollars the previous year, and then fell again from thirteen dollars to nine dollars in 1997, slightly more than half the book value per share (see table 5.2). In April 1996, the board had announced the formation of a special committee, “to provide high-level board oversight of the safety and effectiveness of the utility system’s nuclear operations.”49 Dr. E. Gail de Planque, a former Nuclear Regulatory Commissioner and newly elected Northeast Trustee, chaired the new committee of outside directors. The press release noted, The committee will focus on providing oversight of overall management attention to nuclear safety; of progress in resolving open issues with the NRC, the Institute of Nuclear Power Operations and other independent evaluators of nuclear operations; and of progress in resolving employee, community, and customer concerns. It will receive regular reports from company executives, including the chief nuclear officer, about progress in resolving nuclear safety and effectiveness issues.50

This was too little too late. Before the creation of this special committee, the Corporate Responsibility Committee of the board had been responsible for monitoring nuclear safety concerns; that committee had met only four times and had received only one presentation from management on nuclear safety concerns.51 It had set the precedent for nonperformance. In a visit to the NRC in June 1996, Elizabeth T. Kennan, Northeast board member and chair of that committee, accompanied Messrs. Fox, Busch, and Feigenbaum to a discussion with NRC Commissioner Greta Dicus and staff. This meeting began with Northeast representatives acknowledging, “theirs was a company in trouble whose main mission was to reestablish trust by the NRC, its employees and the citizens of Connecticut.” Ms. Kennan indicated that the Board of Trustees was “distressed at its own failure [to] adequately assess the Millstone situation.” She praised the NRC visit to the Northeast Board meeting, which she credited with the establishment of “an intense commitment” to resolve the Millstone situation.”52 Given all that had taken place over the previous three years, on its face this oversight was inadequate. The approach of monitoring by scheduled board meetings was not functional, particularly with respect to the cascading volume of NOVs and plant forced outages. The Wall Street Journal outlined the difficulties that the Northeast Board of Trustees encountered a few months later in the summer of 1996. It reported that at a special meeting of the Board on September 4, 1996, several members expressed concern with Bernard Fox’s managerial leadership, as evidenced by “flaws in nuclear operations.” W. J. Pate

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TABLE 5.1 Northeast Utilities Consolidated Financial Performance (millions of dollars)

Operating Revenues Operating Expenses: Operation – Fuel Other Operations Maintenance Depreciation Taxes Total operating expenses Operating Income Interest Charges Income (Cont. Operations) Long- and Short-Term Debt Preferred Stock, Common Equity Total Capitalization

1996

1997

$3,792

$3,835

1,140 1,094 416 360 352 3,483

1,294 1,104 502 354 266 3,644

309 278 39 3,947 2,714 6,661

191 272 (130) 4,012 2,622 6,633

Source: Northeast Utilities, annual reports, various years. Notes: Debt and Equity figures for twelve months ended June 3, 1997.

stated that Mr. Fox had “a terrible credibility problem with regulators and the public” and the ensuing discussion among members of the board centered on the question of whether he should be replaced. As one trustee said, “I don’t think that (replacement) should come as a surprise to anyone,” but it was decided that they would “look at his performance in January and if we don’t think he is pulling things together the board TABLE 5.2 Northeast Utilities Statistics on Financial Performance

Earnings per Common Share ($) Dividends per Share ($) Book Value per Share ($) Market Price per Share (Year-end) ($) Deferred Return on Millstone Three

1996

1997

0.30 1.38 17.73 131/8 NA

(1.01) 0.75 17.04 91/2 NA

Source: Northeast Utilities, annual reports, various years. Dividend and book value figures are for twelve months ended June 3, 1997. Notes: Effective with the dividend payable September 30, 1996, the NU Board of Trustees declared dividends on NU’s common shares at $0.25 per share, a 43 percent reduction from the previous $0.44 per share. Effective with the second quarter of 1997, the dividend was suspended.

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has got to do something.”53 This position was taken in a meeting in which the board reduced common stock dividend from 44 cents to 25 cents per share, given that shutdown-related costs at Millstone had reduced second quarter earnings to $11 million from $42 million. Standard and Poor’s and Moody’s Investors had just downgraded the company’s debt, and Moody’s was prepared to downgrade further in the near future. Since January, Northeast stock had lost more that half its value and had closed the previous Friday at $12.125 per share.54 As reported, the lack of urgency in the trustees’ message was stunning. The Millstone shutdown and regulatory, legislative, and media criticism, however, had a limited impact on the current standing of management. The board kept management in place for the rest of the year. Management changes did take place in the fall, after another special investigating committee told the board to do so. According to the Boston Globe, “The Board finally fired nuclear chief Robert Busch in August [1996], to be replaced by Bruce Kenyon, who then ousted several other executives and brought in nuclear executive Adm. David Goebel. ‘To simply establish a new organization [with] existing leadership would not be sufficient,’ Kenyon said.”55 The chief executive, Bernard Fox, took his retirement at the end of 1997, continuing as a paid consultant for two more years. As part of his final compensation package, he received in 1996 $82,000 of his 1995 executive bonus that had been withheld, as well as full retirement benefits of $1,630,000 for his years of service.56 In retrospect, the new management team defined the “problem” as the “failure of leadership which tolerated low standards. The message they gave to people, in blunt terms, was to cut corners.”57 The new president of nuclear operations, Bruce Kenyon, testified before the NRC in 1997 and described this period: The picture that I think characterized the Northeast Nuclear situation, particularly the Millstone situation, was one of deteriorating performance, low standards, falling further and further behind the industry, a growing backlog of important work not accomplished, unclear accountabilities as to who should fix what, a lack of understanding of the true problems, increase in employee concerns with some high profile cases not well handled, growing supervisor and manager frustration, and thus, in spite of many efforts and many programs to try and address that, the organization, at least at the time I arrived, was as close to a dysfunctional organization as I have ever encountered.58

But this litany addressed management process, not the faults in key strategy decisions. The process was driven by implementation plans and programs from Northeast’s corporate competitive response strategy. The

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TABLE 5.3 Northeast Utility Financial Performance, 1988–98 Date

Operating Margin after Depreciation

Net Profit Margin

Return on Common Equity

Dec 90 Dec 91 Dec 92 Dec 93 Dec 94 Dec 95 Dec 96 Dec 97 Dec 98

19.93 20.51 20.80 19.17 23.11 22.76 8.96 5.30 8.15

9.78 10.14 9.42 6.78 9.06 8.58 0.94 −2.60 −3.19

11.91 12.91 12.64 9.02 12.66 11.94 0.08 −5.90 −7.03

Source: Compustat database.

new officers did not address the possibility that the strategy itself was faulty from the point of view of the company and its shareholders, if not from that of senior management. Extending the financial analysis of the company into the shutdown years indicates the impact of the operational collapse at Millstone. Northeast’s operating income margin halved in 1996 and then decreased by another third in the two years, 1997–98, of Millstone shutdown (see table 5.3). The net profit margin was less than 1 percent of revenues in 1996 and was negative in 1997 and 1998. Returns on common equity, one measure of investor returns, were negative in 1997 and 1998. Only after ten years of absorbing the risks of shutdown was there an effect on financial results. By then the management that had designed and implemented the strategy was gone.

CODA: The End Game Millstone Three returned to service following NRC relicensing in July 1998. Millstone Two returned to service in May 1999, also following the commission’s issuing of a new design-based license as if it were a new facility. Under terms set by the Connecticut DPUC, Millstone Three’s capital costs were included for recovery in Connecticut Light & Power’s rate base after the plant achieved 75 percent power for one hundred consecutive hours. Under similar terms, Millstone Two achieved a capacity factor of 86 percent for the period May 11 through July 31, 1999.59 Millstone One never restarted. The company announced that the costs of

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bringing the facility to operating status would have exceeded earnings from sales of power from the facility, and sent the plant into the decommissioning process, ending any possibility of future revenues.60 In May of 1998, the Massachusetts Municipal Wholesale Electric Company (MMWEC), one of the minority owners of Millstone Three, voted to withhold payments for its part of the O&M costs that were incurred at Millstone before the plant returned to service. The MMWEC had previously filed a lawsuit seeking damages from Northeast’s alleged mismanagement of the plant. According to a company press release, the lawsuit charged Northeast Utilities and its Board of Trustees with negligence, misrepresentation, fraud, and deceptive business practices.61 A year earlier, the Connecticut Department of Public Utility Control had disallowed the recovery of costs of replacement power that were incurred during the outage “while the critical path activity [was] directed toward satisfying the design and licensing concerns of the NRC.” These costs were estimated at the time as $600 million; other outage costs, including additional nuclear operation and maintenance expenses and system improvements, were currently estimated at $400 million. The company had noted that it expected to ask for recovery for only $40 million, and would ask for it in a separate proceeding.62 The Nuclear Regulatory Commission removed Millstone Two and Three from the Watch List in May of 2000.63 Soon thereafter, the three Millstone Station plants were sold to Dominion Resources of Virginia, under terms set by the Connecticut Department of Public Utility Control. The sale included the part of Unit Three owned by minority owners, in addition to Northeast’s holdings. Dominion Resources already owned two nuclear facilities and had participated in the restart effort at Millstone; it paid approximately $1.3 billion in cash for the three units, including approximately $105 million for nuclear fuel. The transaction was completed in early 2001, with regulatory approvals by the Nuclear Regulatory Commission, the Connecticut Department of Public Utility Control, and the Massachusetts Public Utility Commission.64 In October 1999, Consolidated Edison had announced that it would acquire Northeast through a merger.65 Although all regulatory approvals were achieved, the merger collapsed in the first quarter of 2001.66 The collapse of the merger was one more step in a long and tortuous struggle to return Northeast to standing as an established electricity distribution company. Whether or not Con Edison or another larger power generation and distribution entity finally acquired Northeast, it ceased being the leading producer and distributor of electricity in New England. It had divested its capacity as a production entity, given the sale of its fossil-generating assets, its Millstone nuclear plants, the subsequent sale of its Seabrook facilities, and the removal of the older Connecticut Yan-

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kee plant from service. The opening of its transmission system to competitive power, a decade later than the date forecast in the 1986 McKinsey strategy recommendation, made Northeast no more than a common carrier of other companies’ kWh. The results, at the end, for those responsible were varied. Owners of the company, the shareholders, had experienced share price reductions from $24 to $13 in 1996 and to $9.50 in 1997, the first full nuclear shutdown year. After the sale of the fossil and nuclear assets, prices returned to the low $20s and after the announced sale of the company to Con Edison, they increased to the $24 level. With cancellation of the Con Edison acquisition, the shareholders registered their preference not to continue as Northeast investors by letting prices decline to close to $21 per share. Those that stayed the course, with the 1986 strategy, ended out where they had started, with low $20s share prices, after periods during shutdown when prices went to half that level.67 The agent for the owners, the Board of Trustees, came through without incurring significant financial loss if not reputational damage. The board had failed to advance the interests of investors at any critical point during the share price downturn in the 1986–96 period. Members of the board, however, were subject to embarrassing questioning in regulatory and court proceedings brought by agencies investigating the collapse in nuclear performance in 1996–98. Although they could not have been comfortable with the questioning as to whether they had failed to perform, they experienced no retribution in those proceedings. No trustee was forced to resign or held financially liable for the performance of their appointees to executive positions in the company. The Nuclear Regulatory Commission, agent for the public safety of nuclear generation, moved on from the Millstone shutdown with its reputation less than intact. The public revelation of a potential LOCA, or loss of coolant accident, in the Millstone Two valve leakage incident, without a forceful NRC reaction (such as a requested plant closing), raised questions nationwide as to the commission’s effectiveness. Given the Northeast’s systemic high-risk management of operations inherent in its strategy, the concern was whether the commission would move to shut down Millstone before another Three Mile Island occurred. The answer was forthcoming in a relatively easy way for the commission: with all three Millstone plants down in outages in 1996, it was possible for the NRC simply to require that they not restart; no more passive a response to nuclear plant breakdown was conceivable. The NRC had displayed, however, its customary initiative in assessing Northeast’s nuclear operations by setting up its own in-plant review teams at Millstone, by following through with NOVs, exacting penalties for mistreating employees, and issuing increasingly more negative and “threatening” warn-

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ings of impending Watch List designation. There was no surprise when NRC Level Three designation was announced. Management had been expecting it for two years. The management team that developed and implemented the competitive strategy from 1986–96 did well throughout this period, in fact, better than any of the other affected interests. Middle-level management associated with forced shutdowns and cited by the NRC as involved in violations did not do well, since they usually were discharged from the company. But the higher the position in the decision-making hierarchy, and the more identified with the strategy, the higher the survival rate and indeed the better the financial results for that executive. By 1995 Messrs. Opeka and Ellis were moving into scheduled retirement, so that their total compensation was at or slightly below that in previous years; but Messrs. Busch and Fox were both active and at compensation levels almost twice what they had realized in the early 1990s. By 1996, the shutdown year, these two executives were subject to cash out, which were not firings, but full buyouts of a contract for Mr. Busch and of retirement benefits for Mr. Fox. Their compensation, between $1.6 million and $3.0 million, was consistent with voluntary separation (see table 4.7 for 1996 and 1997 total compensation). These payments were free of penalties against senior management for destruction of the company.

Strategy as the Cause for Shutdown There are numerous explanations for the shutdown and for the ensuing financial and organizational collapse at Northeast Utilities. The NRC Inspector General blamed the commission for not acting decisively to change management and the direction of ongoing operations during the 1980s, which could have prevented the collapse in 1996. “Millstone changes in program initiatives and management reorganization lulled the NRC staff into allowing an excessive amount of time for proposed corrective action to take effect. The sporadic improvements neutralized the NRC staff willingness to take prompt action.”68 A consultant’s report to the Connecticut DPUC concluded, “Concerned about the need to trim costs in the face of future competition, the managers chose to manage close to the regulatory margin. This decision translated into deferring maintenance, allowing corrective action backlogs to grow, eventually creating a situation that led to a shutdown.”69 That management “chose” this route meant that they decided to take the risk of station collapse in order to benefit from intervening financial gains. A review by the Union of Concerned Scientists discussed the Northeast management problem in

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terms of being outside the “safety margin” and industry practice but went on to criticize the NRC for accepting “as found reactor safety.”70 The Federal Government General Accounting Office noted that growing economic pressure on nuclear generation was the result of entry into wholesale power markets by lower cost non-nuclear suppliers. The GAO cited Millstone as the example: an independent auditor’s review of the Millstone plant in 1996 noted that the need to trim costs in the face of future competition resulted in managers choosing to defer maintenance and allow backlogs of corrective actions to grow, eventually creating a situation that led to a shutdown and several hundred million dollars worth of repairs.71 This was to blame the company for taking on too much risk. The Connecticut DPUC in a 1995 decision instituting partial deregulation of prices for retail power in Connecticut had stated that “to ensure that the plants’ operators are not discouraged from discretionary spending on safety, electric industry restructuring should provide an opportunity at least to recover these expenses.”72 Even so, the DPUC made no such commitment ten years earlier. The responsibility for fault may instead be that management implemented a competitive strategy that promised and then delivered creditable economic performance, but at increasing risk of regulatory shutdown for nuclear safety concerns. The risk was taken, and, by chance, the result was the worst-case shutdown of the three Millstone reactors. One explanation, then, is that management knowingly took on the risk, that the risk was not large initially, but complex nuclear plant operations could not be turned around after it became clear that shutdown was an issue. A variant on this theme, the conclusion of the R. C. Brown and Associates is that “[e]xecutive management lost focus on the safe operation of the nuclear units, placing primary importance on financial issues, geographic expansion and the pending threat of wholesale and retail competition.”73 Under this theory, after the forced shutdowns at Millstone in 1990–91, management attempted to reverse cost containment but with the slow turnaround was constantly distracted by mixed public and internal pressures only to be blind-sided by arbitrary NRC shutdown in 1996. The alternative explanation is that management treated cost containment and NRC rules in nuclear plant operations as if they were conceptual trade-offs, and deliberately chose a low-cost / lax-rule option. In this view, management was far from incompetent, or distracted, in choosing an option that contained increasing risk of NRC shutdown. With top-down budgeting, it implemented a strategy with significant increases in earnings and with significant and sustained risk of nuclear operational problems. That risk was high compared to regulatory risk in

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other strategies; there was never a certainty of shutdown, but it was embedded in the strategy of choice. This implies that cost containment was not merely a source of conflict in solving operational problems, but instead was an established plan for not solving operational problems because it could not permit making the expenditures required to provide those solutions. We have considered whether management intended to reverse cost containment in nuclear, after the 1991–92 plant collapses, but was distracted to the extent of ineffectiveness. If this were true, the proof would be that under regulatory pressure in 1991–92, and again in 1994–95, there would be evidence that plans were put in place to inject substantial resources into Millstone Two and Three to turn around failing plant operations, but then when the pressure was off, management turned again to other financial concerns and failed to follow through. If this were true, the evidence would indicate that management heard the cacophony of impending plant failure but never found the ability and time to turn these plants around before 1996 and the NRC shutdown. Even in broad terms, this version lacks convincing detail. In face of recommendations from the four internal task force studies in 1991–92, the case for completing the design-based programmatic documentation of the three Millstone plants was overwhelming; there was no substantial injection of resources to do this and this lapse alone brought Millstone down. There was no corrective action and the long-term survival of these three plants depended on it. Far beyond distraction or change of plans, there was no systematic management response to increasingly numerous operational breakdowns. The renovation of operator training and licensing, within the context of a new approach to employee-management cooperation on plant operating problems, was never begun. The PEP initiative went only from problem identification to response “formulation”; when it came to the final steps, undertaking corrective action and verifying the results, sufficient funds were never appropriated, and management instead acted as if it sought to evade the cost increases imposed on them by the NRC. Through the mid-1990s corroded pipes were replaced, pumps repaired, unreliable systems bypassed on a piecemeal basis to keep plants operating; no correction process that would have required more significant cost outlays was ever put in place for any major system across the plants. To be sure, there was “distraction” in spending more and more time in meetings, hearings, and conferences with the Nuclear Regulatory Commission, with legislative investigation Committees, and with the press. Nevertheless, these interactions did not substitute for spending in the manner that would be required for substantive turnaround of failing operations at Millstone.

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There are striking instances of management behavior that support instead the “extended risk” explanation, to the effect that cost-containment strategy was forced down from the top, with the acknowledgment of increased regulatory risk of shutdown. The decision to adopt the reengineering initiative, which embodied more cost containment in the face of impending investigations by the NRC of failure to support understaffed systems, occurred twice in the 1990s. The numerous and increasingly hostile communications from the NRC regarding employee concerns and operational failures flatly deny that management was blind-sided. Treating shutdown conceptually as a “hazard” probability, our observation is that there were at least eleven NRC-initiated “events” in the 1991–96 period that had a probability of shutdown. All of those can be associated with a high probability of the hazard occuring (that is, in figure 3.2 the IND curve of high probability describes these events while the SEV curve is possibly descriptive only in the beginning of the period). The Northeast management was told, and it then knew, of the high risk of shutdown by continuing to implement the cost-containment strategy over these confrontations with the Nuclear Regulatory Commission. The 1996 shutdown order was by then an almost certain event, with management existing day to day in the knowledge that it would come. Why so deliberate, then? Management itself did not take losses for this period from the significant and sustained risk of regulatory shutdown. In fact, management experienced little personal loss from this strategy even after forced plant shutdown. The company took on the risk of destruction, while the decision-makers were left relatively unscathed.

Notes

Preface 1. Matthew Wald, “Safety Lapse at Ohio Reactor Is Cited as Potential Peril for Others,” Nation Desk, New York Times, November 20, 2002. Chapter 1 Strategic Challenge at Northeast Utilities 1. Earnings increases were due in part to noncash earnings from ongoing construction of nuclear facilities. Following utility accounting principles, these expenditures were recorded as assets in anticipation of future recovery from ratepayers. 2. Northeast held the operating license for Millstone Three and took the bulk of the power produced; other utilities in the region were partial owners, contributing a share of the capital and expenses and receiving a proportional share of power generated. 3. Northeast Utility (NU), “NU’s History,” website, www.nu.com/aboutNU/ NU-PPP/pppindex.htm, accessed January 15, 2000. 4. A key element in regulatory determinations that Millstone operations did not meet NRC safety standards was a finding that Northeast had lost the cooperation of plant employees in detecting and solving safety problems. Instead, a highly public, adversarial management-employee relationship had developed, with employees believing that they were unable to bring safety concerns to management for fear of reprisal. For example, see Eric Pooley, “Nuclear Warriors: Two Gutsy Engineers in Connecticut Have Caught the Nuclear Regulatory Commission at a Dangerous Game That It Has Played for Years: Routinely Waiving Safety Rules to Let Plants Keep Costs Down and Stay Online,” Time magazine, March 4, 1996, and Daniel P. Jones, “NU Admits to Lies, Violations, Safety and Environmental Crimes: Will Cost $10 Million,” Hartford Courant, September 28, 1999. 5. As the operator / owner of a plant partially owned by several utilities, Northeast was potentially liable for the replacement power costs of nonoperating owners as well as its own. As noted in the Daniel P. Jones’s Hartford Courant article cited in note 4, “the ten part-owners of the Millstone Three plant pursue a civil lawsuit against NU that seeks at least $200 million in costs for replacement power and improvements that were needed after regulators forced the shutdown of all three Millstone plants by 1996.” According to Northeast’s 2000 annual report, the lawsuit was settled out of court in 1999 and 2000, with Northeast paying an amount reported as $38 million cash, plus other considerations. 6. John Hechinger, “Northeast Utilities to Pay $10 Million after Guilty Plea on Millstone Pollution,” Wall Street Journal, September 29, 1999; Daniel P.

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Jones, “NU Admits to Lies, Violations, Safety and Environmental Crimes: Will Cost $10 Million,” Hartford Courant, September 28, 1999. The Hartford Courant quoted the prosecutors as follows: “The company hid the truth about its violations from regulators to save money as part of company-wide cost-cutting to increase profits while preparing to compete in a deregulated energy market.” 7. Although regulatory approvals other than the SEC were in place by late 2000, the merger collapsed. The final grounds for the merger’s collapse were numerous in the swirl of litigation and press releases following the announced failure. In part, the combined company may not have appeared as strong, given conditions imposed by price regulators and an unprecedented lawsuit by the Connecticut State Attorney General in response to strong opposition to the merger by local consumer advocates. In addition to revised appraisal of Northeast’s underlying value, Con Ed apparently feared additional cost increases when retail price freezes ended in 2004 and questioned Northeast’s ability to meet its long-term supply obligations when its current electricity supply contracts end. See Susan E. Kinsman, “NU Deal in Doubt,” Hartford Courant, August 23, 2000; Connecticut Department of Public Utility Control news release, “Staff Weighing Evidence to Make Decision on the Petition of Con Ed and CL&P for a Change of Control, Preliminary Decision Date Delayed,” August 22, 2000; “Con Ed Beats NU to Court: N.Y. Utility Files Suit, Saying Merger Partner Breached Agreement,” Hartford Courant, March 7, 2001. 8. Northeast Utilities, press release, “DPUC Announces Auction of Millstone Nuclear Power Station; Interested Parties Asked to Contact J. P. Morgan,” April 26, 2000; Connecticut DPUC news release, “DPUC and J.P. Morgan Announce the Sale of Millstone to Dominion for $1.3 Billion,” August 7, 2000; Dominion Resources of Virginia purchased all three Millstone facilities for $1.3 billion, taking on the decommissioning of the permanently shutdown Unit One and the operation of the other two facilities. The sale included 100 percent of Millstone One and Two and 93.5 percent of Unit Three, holdings of Northeast and of United Illuminating and almost all other nonoperating owners of Millstone Three. Although Northeast continued to operate its Seabrook facility for several more years, in December 2001 the state of New Hampshire began an auction process for that facility as well, and that auction and sale were completed in 2003. 9. See, for example, R. C. Brown & Associates, Inc., Management Consultants, “On Management Target Objectives in Cost Containment,” in Final Report: Focused Audit of the Connecticut Light and Power Company Nuclear Operations, prepared for the CT DPUC, December 31, 1996, p. VII-c12. CT DPUC Docket 96-10-060, Responses to Interrogatories, Box 78508093.

Chapter 2 Northeast’s Competitive Strategy 1. Northeast’s terminology for its strategic approach varied over time. We will use the term “competitive response strategy” for the strategy throughout the entire period studied. 2. Under the PURPA Act passed by Congress in 1978, electric utilities were re-

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quired to accept power resulting from cogeneration, the production of electricity from heat as a byproduct of an industrial process. Cogenerators could use the power they produced in their own facilities, but had to sell any excess into the utility’s generation mix, and could not sell at retail. 3. John Milne, “Northeast Utilities Bids to Become a Giant in Power,” Boston Globe, January 30, 1990. 4. CT DPUC, Decision issued February 4, 1988, re Connecticut Light and Power, “Introduction,” sections III. B.1. “Policy Issues, Generating Capacity Adjustment, Introduction and Summary,” and B.2: “Positions of the Parties and Interveners, Prosecutorial Division.” Docket No. 87-07-01, 90 P.U.R. 4th 148 1988 WL 391355. 5. NU, Northeast Utilities 1988 Annual Report, p. 8. 6. CT DPUC, Decision issued February 4, 1988, re Connecticut Light and Power, section. III.G.2.c. “Policy Issues: Company Expenses: Electric O&M Expenses: Outside Services Employed, Connecticut Department of Public Utility Control.” McKinsey was a leading consulting firm in corporate strategy and William Ellis, Northeast’s CEO and chairman, had come to Northeast utilities from McKinsey. John Sawhill, of McKinsey’s Washington energy consulting practice and former head of the Federal Energy Administration, led the effort to develop this strategy. 7. NU, “Competition / Cost Containment,” in 1988 Annual Report, p. 19. 8. NU (Bernard Fox), “Strategy to Meet Competitive Threat,” presentation delivered to employees on October 23, 1987. Connecticut DPUC Docket 96-10060, Responses to Interrogatories, Box 785080. Emphasis added. 9. Ibid. 10. Ibid. The emphasis was on the ratio of cost outlays to kWh, focused on costs, not production, and did not make explicit that feedback from reductions in such outlays could cause plant operational breakdowns that would reduce kwh. 11. Ibid. 12. NU, 1987 Annual Report, p. 4. 13. Ibid., Charles Cicchetti, “The New Competitive Battlefield: A View from the Trenches,” p. x. 14. NU (William Ellis and Bernard Fox), “To Our Shareholders,” “Competition / Cost Containment,” and “The First Strategy: Increase the Competitiveness of NU’s Core Business,” in 1988 Annual Report, pp. 2–19. 15. Ibid. 16. Ibid. 17. Ibid., pp. 2–5. Public Service of New Hampshire was in bankruptcy, due almost entirely to its financial involvement in the much-delayed Seabrook Nuclear Power Station, but its underlying utility distribution business appeared sound to Northeast Utilities. Northeast itself already owned a small portion of Seabrook, around 4 percent, through its Connecticut Light and Power subsidiary. 18. “Utility That Foresaw Demand Slump Now has Cash to Adapt,” Wall Street Journal, October 10, 1980. The article contrasts Northeast Utilities’ adverse outlook with New England Electric System’s approach called “cash to adapt,” based on New England Electric having developed lower rates of capacity growth.

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19. Charles Komanoff, “Nuclear Crews Stretch Work, Up Costs,” letter to Wall Street Journal, March 19, 1984. See also Charles Komanoff and Cora Roelofs, Fiscal Fission: The Economic Failure of Nuclear Power, A Report on the Historical Costs of Nuclear Power in the United States Washington, D.C.: Greenpeace, December 1992. U.S. units completed in the early 1970s averaged under half a billion dollars (adjusted to 1982 prices), but “by the end of the 1970s costs had swelled to $1 billion for newly completed projects. . . . Reactors under construction [in 1984] range to almost $4 billion and average $2 billion . . . double that of plants finished only five years [earlier], and five times as great in real terms as the first reactors built commercially at the start of the 1970s.” 20. U.S. Energy Information Administration, Department of Energy Office of Coal, Nuclear, Electric, and Alternate Fuels, “Analysis of Nuclear Power Plant Construction Costs,” Washington, D.C., 1986. Report DOE/EIA 0485. The study period covers Millstone Two as well as Millstone Three, which was in the last wave of nuclear plant construction beginning before 1977. The study excluded Northeast’s older facilities at Millstone One and Connecticut Yankee. Forty of the seventy-five plants in the study achieved commercial operation in the 1980s, after the Three Mile Island event in 1979. 21. Ibid., pp. i–ix. The study also noted that economies of scale due to the construction of larger plants were more than offset by increased costs in these plants, primarily due to their increased construction time. 22. Resource: An Encyclopedia of Energy Utility Terms, 2nd ed. (San Francisco: Pacific Gas and Electric Company, 1992, pp. 90–91. 23. California’s crisis in 2001, in a partially deregulated wholesale auction market, has dissuaded development of retail competition in many other states. Implementation took at least a decade longer than Northeast had expected. 24. CT DPUC, Decision issued February 4, 1988, re: Connecticut Light and Power, section III.D: “Policy Issues: Competition, Connecticut Department of Public Utility Control.” 25. Ibid. The decision also took issue with CP&L’s view of rate subsidies, noting that the company’s industrial rates were comparable to those of other utilities in the region, while their residential rates, at least for those in the 500 to 750 kilowatt-hour range were between the sixth and twelfth highest for the region’s forty-two electric producers. 26. Matthew Wald, “Utilities’ Chapter 11 Prospects,” New York Times, June 26, 1984, p. 1. In addition to Public Service of New Hampshire’s distress due to its investment in Seabrook, other problems related to nuclear facilities included Long Island Lighting Co. (Lilco)’s investment of $3.5 billion in Shoreham, Public Service of Indiana spending of $2.3 billion on Marble Hill before abandonment, and Consumers Power Company of Michigan’s investment of $3.4 billion in Midland. By 1985 Pennsylvania regulators recommended cancellation of Philadelphia Electric Co.’s Limerick Two, after an investment of $897 million, at a point when an additional $2.4 billion would be required before completion. 27. Ibid. 28. Bill Paul, “Berry’s Heresy May Yet Prove Prophecy,” Wall Street Journal, February 17, 1988. 29. Howard P. Allen, quoted in Frederick Rose, “Utilities, Flush with Cash,

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Enter New Fields—But Some Fear Diversification Might Go Too Far,” Wall Street Journal, July 1, 1986. 30. Ibid. Although some analysts at the time recommended returning cash to shareholders—as Alfred Kahn noted, “Why not let the shareholders decide whether to buy stock in a savings bank or drugstore chain?”—we find no approval of this “exit” strategy of paying off investors and gradually closing down. Other analysts noted that changes in the electric business may demand more attention of management time, and diversification might become an even riskier strategy in the future. Erik Zausner of Booz-Alan and Hamilton is quoted in the Rose article as stating, “Having seen the diversification strategies of some of my clients, I must admit that diversification may be akin to throwing a drowning man a rock.” 31. PG&E, 1989 Annual Report, p. 30; PG&E, 1986 Annual Report, p. 38. Our discussion will focus on nuclear facilities until the mid-1990s, and not attempt to address here California’s deregulation and PG&E’s resulting bankruptcy, filed April 6, 2001. 32. PG&E, 1986 Annual Report. 33. PG&E, 1989 Financial and Statistical Report, pp. 2–3. 34. Michael E. Porter, Competitive Strategy: Techniques for Analyzing Industries and Competitors (New York: Free Press, 1980), p. xvi. 35. NU (William Ellis and Bernard Fox), “To Our Shareholders,” in 1988 Annual Report, p. 3. 36. Michael E. Porter, “What Is Strategy?” Harvard Business Review, 74, no. 46, (Nov.–Dec.): 1996. 37. In traditional regulated utility rate-making, capital investments are recovered by including costs deemed reasonable into “rate base.” The rate base is then recovered through depreciation expense over the life of the facility, and rates include an authorized rate of return on the as-yet-undepreciated remainder. Under this recovery mechanism, rates are highest in the initial years, since the authorized rate of return would be applied to the total construction cost, and then would fall as depreciation reduced the unrecovered amount. To avoid “rate shock” from capital-intensive nuclear facilities, the Connecticut DPUC deferred recovery of a portion of the Millstone investment for several years. This adjustment mitigated the initial rate increase and delayed the eventual fall-off in rates; with cost containment, the recovery could take place earlier since recovery of deferred capital could replace eliminated O&M costs without increasing fixed rates. 38. Sue Reinert, “Utility Chief Not a Man Hungry for Power. Paul F. Levy,” Boston Business Journal, January 26, 1987, p. 2. Specifically, cost reductions in generation would meet goals expressed by Chairman Levy of the Massachusetts Department of Public Utilities. The DPU was an active regulator, having barred Massachusetts’s utilities from investing in the high-cost Seabrook nuclear station for several years, to having castigated Boston Edison for poor management. In a January 1987 interview, Levy stated that traditional arguments that there were economies of scale in electric generation no longer applied in New England; he added that, with uncertain future demand, “What you gain in flexibility by building a smaller unit outweighs the economies of a bigger unit.” He also noted

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that large customers could supply power from their own facilities when generation by incumbent utilities became too expensive. 39. NU (Bernard Fox), “Strategy to Meet Competitive Threat,” presentation delivered to employees on October 23, 1987.

Chapter 3 The Nuclear Power Context for the New Competitive Strategy 1. Matthew L. Wald, “Industry Gives Nuclear Power a Second Look,” New York Times, April 24, 2001, p. C1. 2. See, for example, Energy Information Administration Department of Energy Office of Coal, Nuclear, Electric and Alternate Fuels, “Analysis of Nuclear Power Plant Construction Costs,” Report DOE/EIA 0485, Washington, D.C., 1986. 3. Constance Perin, “Operating as Experimenting: Synthesizing Engineering and Scientific Values in Nuclear Power,” Science, Technology and Human Values 23, no. 1 (Winter 1998): 101. 4. Joseph Rees, Hostages of Each Other: The Transformation of Nuclear Energy Since Three Mile Island (Chicago: University of Chicago Press, 1994), p. 17. 5. E. P. Gyftopoulos, “General Reactor Dynamics,” in The Technology of Nuclear Reactor Safety, Vol. 1: Reactor Physics and Control, ed. T. J. Thompson and J. G. Beckerley (Cambridge: M.I.T. Press, 1964), p. 175. Emphasis added. 6. T. J. Thompson and J. G. Beckerley, eds., “Introduction” to The Technology of Nuclear Reactor Safety, Vol. 1: Reactor Physics and Control, p. 2. 7. Nuclear Energy Institute, Guide to Nuclear Energy, website www.nei.org/ intro_lib.html, accessed January 18, 2000. It continues, “U.S. nuclear power plants also use a series of physical barriers to make sure that radioactive material does not escape. The first barrier is the composition of nuclear fuel itself. The radioactive byproducts of the fission process remain locked inside the fuel pellets. These pellets are sealed inside rods made of special metal. The fuel rods are positioned inside a large steel vessel, which has walls about eight inches thick. At most plants, the reactor and vessel are enclosed in a large, leak-tight shell of steel plate. All this is contained inside a massive, reinforced concrete structure—called the containment—with walls that are typically three to four feet thick. The many thick layers of the containment building keep radioactive materials safely inside.” 8. See President’s Commission on the Accident at Three Mile Island (Kemeny Commission), instituted April 5, 1979, report issued October 31, 1979. See also “Sixty Minutes to Meltdown,” NOVA, Public Broadcasting Service, original broadcast date March 29, 1983. 9. Energy Information Administration, Office of Integrated Analysis and Forecasting, U.S. Department of Energy, “An Analysis of Nuclear Power Plant Operating Costs: A 1995 Update,” April 1995. O&M costs, non-fuel operating costs that are expensed for rate-making purposes, are reported in Schedule 402 of the FERC Form 1 filed by all generating facilities. As noted in the report, certain costs, such as insurance premiums, third-party damages, and replacement

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power in the case of an accident are considered operating expenses but are not reported in industry O&M figures. Additionally, NRC regulatory fees and some payroll taxes and fringe benefits, such as health insurance and pension costs, are reported for the entire utility and not included in O&M data. The study notes that these costs would be omitted in Form 1 data related to any generating source, but speculates that some of these costs, particularly insurance, may be higher for nuclear than other generating facilities, and so nuclear costs would be more understated. 10. Ibid. See also p. 3, citing H. I. Bowers, L. C. Fuller, and M. L. Meyers, Cost Estimating Relationships for Nuclear Power Plant Operation and Maintenance, report submitted to the U.S. DOE by Oak Ridge National Laboratory, (Oak Ridge, Tenn., September 1987); International Brotherhood of Electrical Workers, Utility Department Nuclear Guide, vol. 87 (Washington, DC, January 1987); and Sandy Cohen and Associates, “Analysis of the Role of Regulation in the Escalation of Nuclear Power Capital Additions Costs,” ORNL/SYB/88SC557/1 (Oak Ridge, Tenn.: Oak Ridge National Laboratory, July 1989). 11. NRC, “A Short History of Nuclear Regulation, 1946–1999.” Emphasis in original. Online at www.nrc.gov/sec/smj/shorthis.htm, accessed February 2, 2002, p. 25. 12. NU, Roger J. Mattson, testimony on behalf of the Connecticut Light and Power Company, Docket No. 96-10-06, Investigation into Whether the Connecticut Light and Power Company Has Fulfilled Its Public Service Responsibilities with Respect to Its Nuclear Operations, State of Connecticut Department of Public Utility Control, filed June 1997, pp. 2–5 through 2–9. In addition, several additional reports are cited (pp. 2–5 through 2–9, 2–12 through 2–18). 13. Ibid. In a later round of NRC reform, SALP reviews and the Watch List were suspended in 1998 and replaced with a pilot program incorporating a new reactor oversight and assessment program, entitled the Power Plant Review process. 14. Ibid., p. 2-36. 15. Robert A. Kagan and John T. Scholz, “The ‘Criminology of the Corporation’ and Regulatory Enforcement Strategies,” in Enforcing Regulation, ed. Keith Hawkins and John M. Thomas (Boston: Klewer-Nijhoff, 1984), pp. 67–95. See also Robert. A. Kagan, “On Regulatory Inspectorates and Police,” in the same volume. 16. Jonathan Feinstein, “The Safety Regulation of U.S. Nuclear Power Plants: Violations, Inspections, and Abnormal Occurrences,” Journal of Political Economy 97, no. 1 (1989): 115–54. For a discussion of this effect, Todd R. LaPorte and Craig W. Thomas, “Regulatory Compliance and the Ethos of Quality Enhancement: Surprises in Nuclear Power Plant Operations,” Journal of Public Administration Research and Theory, 5, no. 1 (January 1995). LaPorte and Thomas acknowledge that the variation they found in industry attitudes toward regulation may reflect a change in the industry since studies such as Feinstein’s. 17. William C. Wood, Nuclear Safety Risk and Regulation (Washington, D.C.: AEI, 1983), p. 85. 18. Ibid. Wood argues that disincentives for safety are a direct product of severely limited liability for accidents under the Price-Anderson Act. The limit was

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raised in 1988 amendments to the act, with all nuclear operators sharing in public damages beyond the $200 million of insurance required for each plant. According to public interest group estimates, the maximum payout is $9 billion (Safe Energy Communication Council, “Fact Sheet: The Price-Anderson Act,” website www.safeenergy.org accessed September 15, 2003). Nevertheless, given rapidly escalation claims in litigation generally, even the new, higher limits might not be sufficient in worst-case scenarios. Moreover, since coverage for bad events is spread evenly to the industry as a whole, not charged to individual facilities based on their records, any incentive for safety provided by potential large litigation payments must have been reduced, even in later years. 19. LaPorte and Thomas, “Regulatory Compliance and the Ethos of Quality Enhancement,” p. 109. 20. Rees, Hostages of Each Other. Rees’s title refers to the industry realization, after Three Mile Island, that a bad experience at one nuclear facility can bring down the whole industry. As “hostages to each other,” the nuclear operators have chosen to exert pressure on each other to ensure safe operations. 21. Ibid., pp. 37–38. 22. Ibid. 23. Ibid., p. 119. Ralph Nader fought nine years to allow public access to INPO documents that were sent to the NRC, eventually losing a Supreme Court case in 1993. Nader’s argument, that peer pressure would be more effective in the public arena, did not prevail against the counterargument that if reviews were to be made public, the industry would be less forthcoming in its findings. 24. NRC (Thomas Murley), “Developing a Safety Culture,” presentation at the NRC Regulatory Information Conference, Washington, D.C., April 18–20, 1989, p. 2. 25. Ibid. 26. Ibid., p. 3. 27. Ibid., pp. 4–5. The presentation included additional detailed lists of indicators. 28. NRC, Policy Statement on the Conduct of Nuclear Plant Operations, 54 Fed. Reg. 3424, January 24, 1989. 29. Ibid. 30. Ibid. 31. Ibid., pp. 3425–26. 32. William R. Corcoran, “A Vision of Quality: A Workshop on Self-Assessment, Event Analysis and Continuous Quality Improvement,” 1994. CT DPUC Docket 96-10-060, Responses to Interrogatories, Box 78508081. 33. CT DPUC, Decision issued February 4, 1988, re Connecticut Light and Power, Docket No. 87-07-01, 90 P.U.R. 4th 148 1988 WL 391355. The decision stated that expense adjustments and lower profit levels decided in this case would keep the company competitive, and are balanced by allowance of significant levels of Millstone Three into rates, reducing uncertainty of recovery. 34. Ibid., Section III.G. “Policy Issues: Cost Containment.” 35. Ibid., Section IV.F.2.i. “Revenue Requirements: Company Expenses: Electric O&M Expenses.” 36. Ibid.

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37. Decision issued December 21, 1988 re Connecticut Light and Power, Docket No. 88-05-25, 100 P.U.R. 4th 452 1988 WL 391243, Section III.D. “Policy Issues: Cost Containment and Productivity.” 38. Ibid. Northeast’s Connecticut subsidiary CL&P owned 52.93 percent of Millstone Three; thus, the rate case reflects that percentage of the Millstone Three costs. 39. Ibid. Section IV.G.2.f. “Revenue Requirements: Company Expenses: Electric O&M Expenses: Nuclear Residual Expenses.” 40. NU (J. Graves) to NU (E. J. Mroczka), August 24, 1990. CT DPUC Docket 96-10-060, Responses to Interrogatories, Box 78508090. 41. NU (C. F. Sears) to NU (E. J. Mroczka), “NEO Performance versus Resources,” February 6, 1990. CT DPUC Docket 96-10-060, Responses to Interrogatories, Box 78508090. 42. See Nicholas M. Kiefer, “Economic Duration Data and Hazard Functions,” Journal of Economic Literature 26 (June 1988): 646–79. 43. A. Lancaster, “A Stochastic Model for the Duration of a Strike,” Journal of the Royal Statistical Society. Series A,. 135, (1972): 257–71; J. L. Folks and R. S. Chikkara, “The Inverse Gaussian Distribution and Its Statistical Applications: Review,” Journal of the Royal Statistical Society. Series B (Methodological) 40, no. 3 (1987): 263–89. 44. NRC, Systematic Assessment of Licensee Performance (SALP) Report Nos. 50-245/89-99; 50-336/89-99; 50-423/89-99. November 14, 1991. NRC Public Document Room. 45. NRC, Generic letter, May 2, 1989, “Erosion/Corrosion-Induced PipeWall Thinning,” NRC Electronic Reading Room online at www.nrc.gov/readingrm/doc-collections/gen-comm/gen-letters/1989/gl89008.html. 46. NRC, Systematic Assessment of Licensee Performance (SALP) Report Nos. 50-245/89-99; 50-336/89-99; 50-423/89-99. November 14, 1991 NRC Public Document Room; NRC, SALP Report dated 7/28/92 for period 12/16/90 to 2/15/92. 47. NRC, Region 1, Inspection Report, signed December 4, 1991, p. 4. NRC Public Document Room. 48. CT DPUC, Decision issued December 30, 1992, Docket No. 911002, pp. 17–18. 49. CT DPUC, Decision issued May 19, 1992, Docket No. 920105a, pp.12–13. 50. SALP Report dated 7/28/92 for period 12/16/90 to 2/15/92. 51. NRC, Systematic Assessment of Licensee Performance (SALP) Report Nos. 50-245/89-99; 50-336/89-99; 50-423/89-99. November 14, 1992. NRC Public Document Room. 52. NU, “Nuclear Information,” in Forecast and Financial Review, 1991–1996 September 20, 1991, p. 13. CT DPUC Docket No. 96-10-06. NU Response to Interrogatories, Box 7850809; Geoffrey Rothwell, “Profitability Risk Assessment at Nuclear Power Plants under Electricity Guidelines,” white paper, November 15, 2000. In The Utilities Project, Vol. 1, online at www .utilitiesproject.com/documents.asp?grID=229&d_ID=126#. Rothwell found that national averages for capacity factor, capacity utilization, and schedule

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availability consistently rose from 1989 to 1996, with annual improvements ranging from less than 1 percent to as much as 5 percent annually. The reliability factor remained high over the same years, varying from 97.8 percent to 99.2 percent. Rothwell noted that the increases occurred as plants returned to service following retrofits of safety equipment required after Three Mile Island, as capacity utilization increased with reduced production losses during operation, and as both scheduled outages and forced outage rates were minimized. Rothwell defines the annual average capacity factor as output divided by the maximum power that could be generated, a function of the utilization rate (the percent of time the plant operates). The availability factor is in turn a function of the scheduled avilability rate and the reliability factor (1—forced outage rate). 53. NU, “1991 Highlights,” in Financial Forecast and Review, 1992–1996, April 1992, p. 4. CT DPUC Docket No. 96-10-06, Response to Interrogatories, Box 78508091. 54. NU, in “Allegations Root Cause Task Group Final Report,” August 1991, p. 1. CT DPUC Docket No. 96-10-060, Response to Interrogatories, Box 78508100. 55. Ibid., p. 6. 56. NU, “Operability, Reportability, and Communications Task Force Group Report,” August 16, 1991. CT DPUC Docket No. 96-10-060, Response to Interrogatories, Box 78508100. 57. NU, Executive Summary, in “Final Report of the Procedural Compliance Task Force at Millstone Station,” September 1991, pp. 2–4. CT DPUC Docket No. 96-10-060, Response to Interrogatories, Box 78508100. 58. NU, Conclusions, in “NE&O Performance Task Group Report, 1991,” pp. 24–26. CT DPUC Docket No. 96-10-060, Response to Interrogatories, Box 78508100. 59. NU, Appendix A, in “NE&O Performance Task Group Report, 1991,” pp. A9–A27. 60. Ibid., pp. A20–A21. 61. Ibid. 62. Ibid., p. A27. 63. Before 1993 the functions of security, emergency planning, and radiological controls were shown separately; later they were consolidated into plant support. 64. NRC, Systematic Assessment of Licensee Performance (SALP) Report Nos. 50-245/89-99; 50-336/89-99; 50-423/89-99, November 14, 1991. NRC Public Document Room; US GAO, “Nuclear Regulation: Preventing Problem Plants Requires More Effective NRC Action,” (Letter Report), May 30, 1997, GAO/RCED-97-145, p. 14. 65. CT DPUC, Decision issued July 30, 1997, DPUC Investigation into Whether the Connecticut Light and Power Company Fulfilled Its Public Service Responsibilities with Respect to Its Nuclear Operations, p. 9, in Docket No. 9610-06. Response to Interrogatory AG-2, Document No. 16, NRC Staff Actions to Address NU 1991 Self-Assessments, Case No. 96-02S, pp. 10–11. 66. NRC (Edward C. Wenzinger) to NU (E. J. Mroczka), “Report of NRC Meeting with Northeast Utilities,” March 28, 1991, dated May 13, 1991, p. 1. Docket No. 50-423. NRC Public Document Room.

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67. NRC (Edward C. Wenzinger) to NU (E. J. Mroczka), April 30, 1991, p. 1. Docket No. 50-423, NRC Public Document Room. 68. Ibid. 69. NRC (Thomas Martin, Regional Administrator) to NU (William Ellis), “Integrated Assessment of NU Task Force Conclusions, Recommendations and Safety Performance at Millstone,” November 14, 1991, pp. 1–2. Public Document Room. 70. Ibid. 71. NRC (Edward Wenzinger) to NU (John Opeka), NRC Inspection Report on Millstone Nuclear Power Plant Conducted Nov. 12–15, 1991, Millstone Unit 3 Inspection 91-22, Docket No. 50-423, transmitted December 3, 1991. Public Document Room. 72. Ibid., 11. 73. NRC (James M. Taylor) to NU (William Ellis), “Executive Summary of Report of Special Review Group,” issued April 6, 1992, p. 1. Public release of this document was discussed in NRC, “Briefing on the Proposed Transfer of PSNH Ownership of Seabrook to Northeast Utilities,” transcript of meeting held May 11, 1992, in Rockville, Maryland. p. 5. From NRC website http://www.nrc .gov/Nuclear Regulatory Commission/commission/transcripts/19920511b.html. 74. Ibid., Enclosure 1, Executive Summary, p. 1. 75. The “delicate balance” indicates that, while these were significant events, the NRC response was to demand clear and direct corrective action on both operations and personnel front, but was not to signal impending shutdown. On the hazard functions in figure 3.2, we place an observation for a small event “t,” a hazard (shutdown) probability, closer to the SEV than the IND curve. 76. NRC, SALP Report dated 7/28/92 for period 12/16/90 to 2/15/92. The boardroom meeting was reported in R. C. Brown and Associates, Inc., Final Report, Focused Audit of the Connecticut Light and Power Company Nuclear Operations, prepared for the CT DPUC, December 31, 1996, Chapter 4, p. 17. CT DPUC Docket No. 96-10-060. NU Response to Interrogatories, Box 78508093. 77. CT DPUC, Decision issued July 30, 1997, DPUC Investigation into Whether the Connecticut Light and Power Company Fulfilled Its Public Service Responsibilities with Respect to Its Nuclear Operations, p. 8. Docket No. 9610-06. 78. Ibid., pp. 9–10. The prediction was directed to CL&P (i.e., Northeast) management’s attention seven years prior to these proceedings, and, unfortunately, came to reflect accurately the current situation of the NU nuclear program. 79. Ibid., p. 11. Although this statement is not an NRC directive, it is an interpretation by extremely knowledgeable analysts; it would support an observation on the hazard functions in figure 3.2, close to the point of inflection of the IND curve—that is, indicative of a high probability of shutdown. 80. Quoted in Ibid., p. 11. 81. Lawrence Ingrassia and Cynthia Grisdela, “Seabrook Plant Gets NRC Nod for Full Power: Opponents Vow Lawsuits; Panel Rejects Argument Tied to Evaluation Plan,” Wall Street Journal, March 2, 1990. The article notes that the initial cost estimates were for under $2 billion for two reactors, but by the end

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had escalated to more than $6 billion for one reactor, due to delays and overruns as regulatory standards changed. 82. Lawrence Ingrassia, “Northeast Utilities Makes Bid It Values at $2 Billion for Public Service of New Hampshire,” Wall Street Journal, January 13, 1989; “Northeast Utilities Files Plan to Make Utility Firm a Unit,” Wall Street Journal, March 23, 1989; “Business Brief—Public Service of New Hampshire Firm Says Twenty-Five Parties Show Interest in Buying Assets,” Wall Street Journal, April 11, 1989; David Stipp, “New Hampshire Public Service Gets Rival Offer: New England Electric Raises Stakes with a Package Totaling $2.35 Billion,” The Wall Street Journal, April 6, 1989; “Business Brief—Central Maine Power Company: Proposal Dropped to Merge with a Utility in Vermont,” Wall Street Journal, May 11, 1989; Lawrence Ingrassia, “PSNH Tells Federal Judge a Resolution of Chapter 11 Realignment May be Near,” Wall Street Journal, August 14, 1989. 83. “Northeast Utilities Unit Offers to Settle Seabrook Rate Case,” Wall Street Journal, August 30, 1989. United Illuminating had already completed the state prudence review of its share of Seabrook, with its Connecticut regulators allowing 56 percent of United Illuminating’s share of the plant into the utility’s rate base. 84. Lawrence Ingrassia, “Seabrook Partner Considers Seeking PS New Hampshire,” Wall Street Journal, September 5, 1989; “Northeast Utilities Unit Offers to Settle Seabrook Rate Case,” Wall Street Journal, August 30, 1989; Robert M. Bleiberg, “Editorial Commentary: The Saga of Seabrook—It’s Finally Headed for a More-or-Less Happy Ending,” Barron’s, November 20, 1989; Ingrassia and Grisdela, “Seabrook Plant Gets NRC Nod for Full Power.” 85. Lawrence Ingrassia, “Northeast Utilities Seeks to Calm Critics of Its Plan to Buy PS New Hampshire,” Wall Street Journal, December 1, 1989; “PS New Hampshire Board Endorses Bid by Northeast Utilities, Wall Street Journal, December 14, 1989; “Northeast Utilities’ PS New Hampshire Bid Clears Hurdle,” Wall Street Journal, December 15, 1989; “PS New Hampshire Says Plan Is Clear by Holders, Creditors, Wall Street Journal, March 12, 1990; “Northeast Utilities Purchase Plan Cleared on PS New Hampshire,” Wall Street Journal, April 24, 1990. 86. NRC, “Briefing on the Proposed Transfer of PSNH Ownership of Seabrook to Northeast Utilities,” transcript of meeting held May 11, 1992, in Rockville, Md., pp. 5–6. NCR website at http://www.nrc.gov/Nuclear Regulatory Commission/ commission/transcripts/19920511b.html. 87. NU (William Ellis), quoted in ibid. 88. Ibid., pp. 73–74. 89. NRC (Thomas E. Murley, Director, Office of Nuclear Reactor Regulation), to NU (William Ellis), May 19, 1992, Docket No. 50-443, p. 1. 90. Ibid. 91. NRC (James M. Taylor, Executive Director for Operations) to NU (William Ellis), June 3, 1992, pp. 1–2. NRC Public Document Room. 92. Ibid. These conditions, particularly the reference to both continued employee concerns and the failure to finalize safety performance plans required six months earlier, constitute, in our judgment, a point on the IND curve, the high probability of continuous hazard (see figure 3.2). As a “threat” of shutdown at

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Millstone, these conditions require a new expenditure level on safety-related equipment and activities. There is no indication that Northeast management intended to comply. We consider this observation as beyond the inflection point on the IND curve in figure 3.2. 93. NU, “1991 Highlights,” in Financial Forecast and Review, 1992–1996, April 1992, p. 4. CT DPUC Docket No. 96-10-060, Response to Interrogatories, Box 7850809. 94. NU (Graves), memo to Mroczka, August 24, 1990, CT DPUC Docket 9610-060, Responses to Interrogatories, Box 78508090. 95. NU, 10K year-end reports for 1998, 1999, 2000.

Chapter 4 Revisiting Competitive Strategy in the Mid-1990s 1. NU, 1992 Annual Report. 2. NU (P. R. McLaughlin) to FBRC Chairmen, August 4, 1993. CT DPUC Docket No. 96-10-060, Responses to Interrogatories, Box 7850878 3. NU, 1991 Annual Report, “Cost Management,” “Financial and Statistical Section, Management’s Discussion and Analysis,” pp. 14, 21. 4. Ibid., p. i; William Ellis and Bernard M. Fox, “Letter to Our Shareholders,” in ibid. p. 3; Eric Zausner, “Utility Business Dynamics,” in ibid., p. 11. 5. NU (Bernard Fox), Presentation to EEI Financial Conference, October 13, 1992, pp. 1–2. He noted that the combined system, with over half its capacity in nuclear generation, would not require the large outlays on stack precipitators to comply with the Clean Air Act, which coal and oil-based power systems were then confronting. 6. Ibid., p. 3. 7. Ibid., pp. 5–7. 8. “CL&P Working to Reduce Cost of Power from 25 NUGs Totaling Almost 600 MW,” in Northeast Power Report (New York: McGraw-Hill, March 5, 1993), 6 ff. The regulatory proceeding in question was an attempt by Northeast’s subsidiary, Connecticut Light and Power, to cancel or buy out of contracts with high-priced non-utility generators, which they had entered into under PURPA requirements. 9. NU, 1993 Annual Report, “Letter to Shareholders” by William Ellis and Bernard Fox; “Becoming More Profitable”; “Meeting Market Needs,” by Robert E. Busch; “Targeting for Excellence,” pp. 3–13. 10. NU, Financial Forecast and Review, 1993–1997, “Company Highlights 1993,” July 1993, p. 2. 11. NU, 1993 Annual Report, p. 2. 12. Ibid., pp. 8–9. 13. NU, Nuclear Functional Budget Review Committee Monthly Variance Reports, various years, CT DPUC Docket No. 96-10-06, Responses to Interrogatories, Box 7850878. 14. NU, Financial Forecast and Review, May 1994, p. 1. 15. NU, 1994 Annual Report, pp. 3–17.

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16. Ibid., “To Our Shareholders” by William B. Ellis and Bernard M. Fox, pp. 2–3. The 1994 report was issued Spring 1995, and this essay was dated March 1995. 17. NU, 1994 Annual Report, pp. 3–17. 18. Connecticut DPUC, Decision issued September 9, 1994, DPUC Investigation into Retail Electric Transmission Service, Docket No. 93-09-29. 19. The Connecticut Department of Public Utility Control had decided to “phase in” the large addition to the rate base represented by Millstone Three and therefore to defer investment recovery. This limited current increases while keeping higher rates in place longer into the future. See chapter 2, note 37, for additional discussion of ratemaking. 20. R. C. Brown and Associates, Inc., Management Consultants, Final Report: Focused Audit of the Connecticut Light and Power Company Nuclear Operations, prepared for the CT DPUC, December 31, 1996. CT DPUC Docket No. 96-10-06, Responses to Interrogatories, Box 78508093. 21. Ibid., Chapter II, pp. II-1–II-2. 22. The essentials of the agreement to initiate PEP are as follows: Northeast had to commit additional spending in operations to the Performance Enhancement Program for the addition of 250 workers at the Millstone site, at a cost of $40 million a year for three years. The Nuclear Regulatory Commission demanded that Northeast provide annual reports on this spending and deliver notice to the commission before making any cuts in nuclear spending overall. 23. NU to NRC, Report to NRC on Performance Enhancement Program, March 27, 1992, presented at the meeting of Northeast and the Nuclear Regulatory Commission. The handout was included as Enclosure 2 to a letter from Charles Hehl, Director, Nuclear Regulation Commission, to John Opeka, Northeast Utilities, April 21, 1992, Docket Nos. 50-245 et al., pp. 6–11. NRC Public Docket Rooms. 24. Ibid., p. 18. 25. NU, “1991 Highlights,” in Financial Forecast and Review, 1992–1996, April 1992, p. 4. 26. NU, “Corporate Update,” in Financial Forecast and Review, September 1992, p. 6. 27. NU, 1992 Annual Report, “Building a Stronger Company,” “Financial and Statistical Section, Management’s Discussion and Analysis,” pp. 10, 22. 28. NU, “Corporate Update,” in Financial Forecast and Review, September 1992, p. 6. 29. NRC (James T. Wiggins) to NU (John Opeka), August 17, 1992, p. 1; Enclosure 2, p. 1. NRC Public Document Rooms. 30. U. S. General Accounting Office, “Nuclear Regulation, Preventing Problem Plants Requires More Effective NRC Action,” Appendix III:3, letter report issued May 1997. GAO/RCED—97-145. 31. The intense monitoring by the NRC of company compliance with the separate list of renovations constitutes a “hazard event.” The placement of permanent NRC inspection teams on site at Millstone was an unusual step and a Commission commitment that had to reflect the threat of more severe regulatory action in the face of non-compliance. The costs to the NRC alone would require

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that this observation be substantially to right of the point of inflection of the IND curve in Figure 3.2. 32. NRC, Notice of Violation and Proposed Imposition of Civil Penalty— $100,000 and Demand for Information, transmittal letter, sent May 4, 1993, to NU (Ellis), Docket No. 50-423, p. 5. NRC Public Document Rooms. 33. Ibid. The highly negative NOV constitutes a significant “event” on the IND hazard function in figure 3.2. The specific NRC assertions that previous faults in safety operations and personnel relations had not been corrected make it the equivalent of notice with a high probability of shutdown for noncompliance, so that this observation belongs to the right of the 1992 observations at the same or higher probability of shutdown. 34. Ibid. 35. NRC, Initial Systematic Assessment of Licensee Performance (SALP) Report, July 20, 1993, transmittal letter, p. 1. NRC Public Document Rooms. 36. Ibid. 37. NRC (Thomas Martin, Regional Administrator), to NU (John Opeka), Notice of Violation and Proposed Imposition of Civil Penalty—$237,500, December 3, 1993, p. 2. NRC Public Document Rooms. 38. NRC, “Independent Review Team Report, Millstone Unit 2,” September 9, 1993, pp. 10–11. CT DPUC Docket No. 96-10-060, Responses to Interrogatories, Box 78508097; NRC letter to NU (John Opeka) transmitting special inspection, September 22, 1993, NRC Docket No. 50-336. 39. NU, “1994 Millstone Horizontal Self-Assessment Report,” December 16, 1994. CT DPUC Docket No. 96-10-060, Responses to Interrogatories, Box 78508082. 40. NU, “MP2 2-CH-442 Leak Sealing Activities, Revision 1,” Special Report for the Nuclear Quality and Assessment Services Department, October 19, 1993, pp. 2–8. CT DPUC Docket No. 96-10-060, Responses to Interrogatories, Box 78508082. 41. See Scott Allen, “Top Power Producers Enter New Era,” Boston Globe, September 29, 1996, p. a1. 42. NRC, SALP Report, for Units 1, 2, 3, 4/3/93–7/9/94. pp. 1–2. NRC Public Document Rooms. The focus on the failure to resolve “long-standing weaknesses” constitutes an observation on the IND hazard function not only of a high probability of shutdown but of an increasing probability that the NRC will order that to take place. This observation is important for indicating that there was no abatement in the high probability of hazard, on the IND function in figure 3.2, after the initiation of PEP in 1992. 43. Ibid. 44. NU, 1994 Annual Report, pp. 3–17. 45. R. C. Brown and Associates, Inc., Management Consultants, Final Report: Focused Audit of the Connecticut Light and Power Company Nuclear Operations, prepared for the CT DPUC, December 31, 1996, Chapter VII, p. VII38, quoting remarks made by CEO Bernard Fox, Sturbridge, Mass., February 1, 1996. DPUC Docket No. 96-10-060. 46. Ibid. 47. Connecticut DPUC, Decision issued July 30, 1997, DPUC Investigation

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into Whether the Connecticut Light and Power Company Fulfilled Its Public Service Responsibilities with Respect to Its Nuclear Operations, pp. 6–7. CT DPUC, Docket No. 96-10-06. 48. Ibid., pp. 10–11. 49. Ibid., pp. 11–13. Northeast training failures were also tied to cost cutting. In a 1999 complaint against Northeast, NRC’s allegations, to which the company pled guilty, centered on charges that it had falsified records to cover deficiencies in training its nuclear operators. The government noted, “These failures occurred at a time when Northeast Nuclear was seeking to increase efficiency and profit margins while preparing to operate in a deregulated environment.” See U.S. v. Northeast Nuclear Energy Company and Northeast Utilities Service Company, Government’s Version of the Offense and Sentencing Guideline Calculation, September 27, 1999, p. 9. 50. NU, “Report to NRC, PEP Phase II Completion Report,” 1992. NRC Public Documents Room. 51. Brown and Associates, Inc., Final Report, Chapter VI, pp. VI-14–VI-15. 52. Ibid., Chapter VII, p. VII-36. 53. Institute of Nuclear Power Operators (INPO), 1995 INPO Corporate Evaluation Readiness Assessment Report, February 13, 1995. CT DPUC Docket 96-10-060, Responses to Interrogatories, Box 78508083. 54. Joseph Rees, Hostages of Each Other: The Transformation of Nuclear Energy Since Three Mile Island (Chicago: University of Chicago Press, 1994), pp. 113–117. 55. NRC (Thomas Martin) to NU (William Ellis), June 19, 1995. NRC Public Document Rooms. 56. That the chief executive officer of the NRC felt it was necessary to confer with the Northeast Board of Trustees testifies to the level of NRC concern with the low quality of Millstone plant operations. Elsewhere, on the rare occasions that such a visit was made or even threatened, the target company made fundamental changes in the management team responsible (as at Peach Bottom). No such changes were forthcoming at Northeast. We would consider this a “hazard event” on a high IND curve in figure 3.2, indicative of a clear warning of shutdown if operations continued to develop at the poor level achieved in 1993–94. 57. NU, 1991 Annual Report, p. i. 58. NU, Financial Forecast and Review, September 1992, p. 6. 59. Economic value is a measure of after-tax cash flow that a business generates, less the cost of capital deployed to generate the cash flow. Economic value focuses on shareholder value, looking at real profit versus paper profit. It recognizes the cost of equity and an analysis of shareholder’s expected return relative to the risk implicit in the investment. In the case of Northeast, the comparison is made with investments in other large electric utilities nationwide. 60. Brown and Associates, Inc., Final Report, Chapter VII, pp. VII-8–VII-12. 61. Ibid., p. VII-9. 62. Ibid., p. VII-22. 63. NU Budget Administration, Underlying Performance Reward Plan, 1993, January 1994. CT DPUC Docket No. 96-10-060, Responses to Interrogatories, Box 78508078.

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64. NU, Underlying Nuclear Performance Incentive Program, 1995 year-end report, March 2, 1996. CT DPUC Docket No. 96-10-060, Responses to Interrogatories, Box 78508078. 65. Michael Jensen, “Paying People to Lie: The Truth about the Budgeting Process”; Harvard Business School Working Paper 01-071, September 2, 2001, p. 8. 64. Ibid. 65. Ibid., p. 28. 66. Ibid. 67. Ibid. 68. Ibid., p. 27. 69. PG&E, 1998 Annual Report, p. 3. 70. “U.S. Monthly Operating Reports.” McGraw-Hill, Platts Energy Infostore, database, various months.

Chapter 5 Northeast Strategy and Regulatory Shutdown of the Millstone Plants 1. NRC, James M. Taylor to Commissioners, “Staff Action Regarding Operation of Millstone Nuclear Power Plant Unit 1,” January 23, 1996. NRC Reading Room. 2. The NRC defines “design basis” as that body of plant-specific information that identifies the functions performed as NRC-certified in a structure, system, or component of a facility and at the level of temperature and pressure of that performance. It also specifies values or ranges chosen for controlling parameters. The Final Safety Analysis Report specifies the design basis of the plant that is safe to operate. The FSAR is updated by ongoing safety analysis as modifications to the plant take place and are approved by the NRC as licensee of the plant. 3. NRC (William T. Russell) to NU (Robert Busch), December 13, 1995. NRC Public Document Rooms. The 10CFR 50.54(f), while not specifically an NOV, constituted the first written statement of a high probability of shutdown (see the IND hazard function in figure 3.2) of Millstone facilities, given that Northeast was not operating in compliance with its license specifications at Millstone One. This observation on the IND hazard function for 1995 appears to be for a probability in excess of 0.9 involving questions of basic safety. It could not likely be considered an observation on the SEV curve, however, where the probability increases exponentially in a short interval before shutdown, because of the series of high probability events preceding this one. 4. NRC (Roy Zimmerman) to NU (Robert Busch), December 15, 1995. NRC Public Document Rooms. 5. NRC, “NRC Failure to Adequately Regulate—Millstone Unit 1,” Case No. 95-771, Office of the Inspector General. Event Inquiry, December 21, 1995, Executive Summary, p. 4. NRC Public Document Rooms. 6. Ibid., p. 5. 7. NRC (James M. Taylor) to NU (Robert Busch), January 29, 1996, p. 1, copy NRC Public Document Rooms. Watch List designation constitutes in our

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judgment a “hazard event” on the IND curve of figure 3.2, the first in 1996, continuing the high probability of shutdown. 8. NRC (Jacque Durr) to NU (Ted Feigenbaum) February 8, 1996. NRC Public Document Rooms. 9. NU, Assessment Team Report, Millstone Employee Concerns, “Assessment of the Millstone Nuclear Safety Concerns Program,” January 29, 1996, p. 1. CT DPUC Docket 96-10-060, Responses to Interrogatories, Box 78508082. 10. See NU, Nuclear Workforce Reduced,” Northeast Utilities System News Release, January 11, 1986; and NU, “NU Announces Nuclear Reorganization,” Northeast Utilities System News Release, January 16, 1996. 11. NU (Bernard Fox) to key management group re: core process reengineering, January 20, 1994. 12. NU, “Updated Final Safety Evaluation Report, ACR 7007 Event Response Team Report,” February 22, 1996, CT DPUC Docket No. 96-10-060; also quoted in NRC (William T. Russell) to NU (Robert Busch), March 7, 1996, submitted for public access March 8, 1996, pp. 1–2, CT DPUC Docket No. 9610-060, Responses to Interrogatories, Box 78508082. 13. Ibid. 14. Ibid. 15. Ibid. 16. NRC (William T. Russell) to NU (Robert Busch), March 7, 1996, p. 2. NRC Public Document Rooms. 17. NU (Fred Dacimo) to NRC, March 8, 1996. NRC Public Document Rooms. 18. NRC News Release No. 96-49, issued March 8, 1996, with both letters attached (William T. Russell) to NU (Robert Busch), March 7, 1996, online at NRC Electronic Reading Room, http:ww:nrc.gov/reading-rm/doc-collections/ news/1996/96-049.htm The release of the ACR 7007 Report made it clear to all constituencies of the NRC that Northeast had not complied with commission requirements for corrections in faulty systems and operations (including personnel relations on the plant floor between safety engineers and management). With the Watch List Category Two designation for the Millstone site, it was just a matter of time before Category Three designation (shutdown). This constituted a point on the IND curve and also the SEV curve for an “event” with a high probability of shutdown at the end of the first quarter of 1996, in figure 3.2. 19. NRC Weekly Information Report, Week Ending March 1, 1996, online at NRC Electronic Reading Room, http://ww.nrc.gov/reading/rm/doc-collections/ commision/secys/1996/sccv1996-049scy.html. 20. NRC (Samuel Collins), Director’s Decision Reviewing Northeast Plant Closures, February 11, 1998, http://www.nrc.gov/reading-rm/doc-collections/ petitions-2-206/directors-decision/1998/dd-98-01.pdf 21. NRC (William T. Russell) to NU (Robert Busch), April 4, 1996, p. 1. NRC Weekly Information Report Week Ending April 17, 1996, online at NRC Electronic Reading Room, http://www.nrc.gov/reading-rm/doc-collections/commission/secys/ 1996/secy1996–081scy.html. 22. NRC (Wayne D. Lanning) to NU (Ted Feigenbaum), June 6, 1996, pp. 1–2. NRC Public Document Rooms. The letter also discusses conditions at the

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Connecticut Yankee facility; only Seabrook remains unscathed. NRC Public Document Rooms. 23. NRC (William T. Russell) to NU (Ted Feigenbaum), Special Inspection of Engineering and Licensing Activities at Millstone Units Two and Three (NRC Inspection Report 50-33-6-96-201), June 22, 1996, p. 1. CT DPUC Docket No. 96-10-060, Responses to Interrogatories, Box 7850802. 24. Ibid., pp. 1–3. 25. NU (M. D. Quinn) to NRC, PEP Close Out Report, May 10, 1996. CT DPUC No. Docket 96-10-060, Responses to Interrogatories, Box 78508099. 26. Ibid. 27. NU (Michael Brothers) to NRC, Licensee Event Report (LER) 96-007-00, for event dated April 3, 1996, submitted May 2, 1996. CT DPUC Docket No. 96-10-060, Responses to Interrogatories, Box 78508100. 28. NU, “Millstone Unit Three Loss of Confidence in the MP-32 Configuration and Current Licensing Basis,” ACR 13302, July 1, 1996 Root Cause Investigation, Revision 1. CT DPUC Docket No. 96-10-060, Responses to Interrogatories, Box 78508082. 29. Data from table 3.5, reproduced graphically for convenience here. 30. The t-stats for significance of negative b are –2.10, –2.32, and –1.17 for the three plants respectively. 31. NRC (James M. Taylor) to NU (Robert Busch), June 21, 1996, p. 1. Taylor, the Executive Director for Operations of the NRC, summarized NRC discussions as indicating that Millstone station performance “has been of concern to the NRC for the last five years, that he (Taylor) had met with the Board of Trustees in March of the previous year, and that plus a number of other initiatives had not produced any success in resolving significant performance concerns with procedural adherence, work control, and communications and teamwork between organizations. There were continued weaknesses in correcting identified problems with poor self-assessment and quality verification, and there was an inappropriate response to employee safety concerns.” 32. Ibid. The increasing NRC oversight at the Millstone site throughout this period was another sign of high increasing hazard, consistent with the IND curve in figure 3.2. 33. Ibid. 34. NRC (James M. Taylor) to NU (Robert Busch), June 28, 1996. NRC Public Document Rooms. This event constitutes the last observation on the hazard functions prior to the probability of hazard (i.e., shutdown) of 1.0 in figure 3.2. Both hazard functions have the same terminal point for the NRC meeting at the end of the second quarter of 1996. 35. Eric Pooley, “Nuclear Warriors: Two Gutsy Engineers in Connecticut have Caught the Nuclear Regulatory Commission at a Dangerous Game that It Has Played for Years: Routinely Waiving Safety Rules to Let Plants Keep Costs Down and Stay Online,” Time Magazine, March 4, 1996. 36. Ibid. 37. See, for example, the aforementioned Time magazine article. 38. For example, Commissioner Diaz stated that the commission may have overreacted and included changes in its Millstone restart plan that were related

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to good management but were not safety critical, and therefore outside the commission’s mandate. He suggested that part of the overreaction was because in the past the commission had not ensured that nuclear plant operators had maintained an adequate design basis for their structures, systems, and components. Nils J. Diaz, “Nuclear Regulatory Oversight,” address to 1997 NRC Regulatory Information Conference, NRC Office of Public Affairs, April 10, 1997. 39. “Legislators Want Answers From Northeast Utilities Boss,” News-Times, Danbury, Conn., March 21, 1996. 40. Ibid. 41. Ibid. 42. NU (Bernard Fox), written responses to members of the Joint Committee on Energy and Technology, Connecticut General Assembly, April 2, 1996; May 3, 1996. CT DPUC Docket No. 96-10-060, Responses to Interrogatories, Box 78508091. 43. Connecticut General Assembly, Joint Committee on Energy and Technology, Transcript of Hearing 3 of 8, April 22, 1996. 44. Ibid. 45. Ibid. 46. The key accidents were described repeatedly in the media. For example, a Boston Globe article in September 1996 began with a graphic retelling of the 1993 valve-peening incident: As soon as the bolt broke, Jack Keenan knew he’d lost the gamble. On a TV monitor in the control room of the Millstone Two nuclear reactor, the plant director watched in shock as his work crew fled the scalding jet of radioactive steam spewing from the damaged valve. Under pressure to save money for plant owner Northeast Utilities, Keenan had chosen a risky strategy. Rather than shut down the plant to stop a small but persistent leak, a crew had been working on the valve for three months while the plant kept running—avoiding $500,000 a day in lost electricity production and earning Keenan a written commendation in the process. But, then, workers broke one of four bolts holding the valve together, and the leak became a powerful jet of radioactive steam. For two agonizing hours, reactor officials prayed the valve would hold together while Millstone Two went through an emergency shutdown. The valve held, but Keenan knew he was lucky the accident hadn’t killed his work crew or released radiation into the atmosphere. “I knew in an instant we had made ourselves vulnerable,” confessed Keenan, who ordered the Aug. 5, 1993, emergency shutdown, in a letter to federal regulators. That brush with disaster at Millstone Two was a signal event in a new and potentially dangerous era for New England’s biggest source of electricity, nuclear power, and for the thirteen million New Englanders who depend on it. (Scott Allen, “Top Power Producers Enter New Era,” Boston Globe, September 29, 1996, p. a1.) 47. Ibid. 48. Ibid. 49. NU, “NU Reports Lower First-Quarter Earnings and Temporary Cost Control Measures; Announces New Board Nuclear Oversight Committee,”

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Northeast Utilities News Release, April 23, 1996. CT DPUC Docket No. 96-10060, Responses to Interrogatories, Box 78508088. 50. Ibid. 51. NU (Bernard Fox), written response to members of the Joint Committee on Energy and Technology, Connecticut General Assembly, May 3, 1996, Answer to Question 52. CT DPUC Docket No. 96-10-060, Responses to Interrogatories, Box 78508091. 52. NRC memorandum (Anthony W. Markley) to NRC (Greta Dicus), courtesy visit by Northeast Utilities Company, June 21, 1996, p. 1. In the same meeting, Fox took exception to the terminology used in the meeting that Northeast was on a “get well program” because he considered that to be “pejorative.” 53. “Regulators, Trustees Put Pressures on Chief of Northeast Utilities,” Wall Street Journal, October 7, 1996, pp. 1–3. 54. Ibid., p. 2. 55. Ibid. 56. Bruce Kenyon was able to operate independently of previous division and plant management. He put “recovery teams” in place at each of the Millstone plants and brought in operations-level management from other nuclear companies, including Virginia Electric Power, Carolina Power and Light, Pennsylvania Electric Company, and Duke Power. To oversee plant recovery programs, the Nuclear Regulatory Commission ordered Northeast to hire an independent contractor to administer an independent corrective action verification program (ICAVP). The contractor was to verify the adequacy of programs to correct design control deficiencies, identify degraded / non-conforming conditions and assure corrective action. This ICAVP was to begin in mid-1997 and last for a fourto-five month period. 57. Bob Wyss, “Millstone Three: Could Financial Pressure Trip the Switch at a Troubled Nuclear Power Plant?” Providence Journal-Bulletin, February 1, 1998, p. 1. 58. NRC, Testimony of Bruce Kenyon, Transcript of NRC Briefing on Millstone by Northeast Utilities and NRC, January 30, 1997, pp. 7–10. NRC website. 59. NU, SEC 10Q filing, August 13, 1999. 60. Dan Haar, “NU Will Not Restart Unit 1,” Hartford Courant, July 18, 1998. 61. “MMWEC Stops Payment to Northeast Utilities for Millstone 3,” News Release, Massachusetts Municipal Wholesale Electric Company, Ludlow, Mass., May 29, 1998. 62. CT DPUC, Decision issued July 30, 1997, DPUC Investigation Into Whether the Connecticut Light and Power Company Fulfilled Its Public Service Responsibilities with Respect to Its Nuclear Operations, p. 17. 63. “Mich., N.Y. Nukes Remain Under Safety Scrutiny,” NRC Press Release, Reuters New Service, May 25, 2000. By mid-year 1999, Northeast already had auctioned of all its non-nuclear generating facilities. Cf. Megawatt Daily, July 7, 1999, and Christopher Keating, “NU Unit Sells Plants To Con Ed,” Hartford Courant, July 27, 1999; “Consolidated Edison To Acquire Northeast Utilities In $19 Billion Strategic Combination: Creates Nation’s Largest Electric Distribution

134

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Utility With Over 5 Million Customers,” Press Release of Consolidated Edison, Inc., and Northeast Utilities, October 13, 1999. 64. NU. Joint Press Release of Northeast Utilities and Dominion Resources, August 7, 2000; “Regulators Set Down Rules for Sale of Nuclear Plants,” Hartford Courant, April 20, 2000, “Dominion Completes Millstone Purchase,” Dominion News Release, March 31, 2001. Accessed at www.dom.com/news/ dom2001/ pr0331.html. 65. “Consolidated Edison To Acquire Northeast Utilities In $19 Billion Strategic Combination: Creates Nation’s Largest Electric Distribution Utility With Over 5 Million Customers,” Press Release of Consolidated Edison, Inc., and Northeast Utilities, October 13, 1999. 66. NU, “Northeast Utilities Files Suit Against Consolidated Edison to Recover Value of Breached Merger Agreement for Northeast Utilities Shareholders,” News Release, March 12, 2001. The merger collapsed in a flurry of counterclaims and lawsuits. 67. Stock prices from Marketwatch.com. 68. NRC, Office of Inspector General, Report OIG-97A-01, August 21, 1997; NU, “Millstone Lessons Learned Report, Part 2: Policy Issues,” SECY-97-036, February 12, 1997; “Millstone Lessons Learned Task Group Report, Part 1: Review and Findings,” September 1996, Memorandum from the Executive Director for Operations (EDO) September 19, 1996. 69. Quoted in John Ahearne, “Testimony Before the Select Committee on Ontario Hydro Nuclear Affairs,” transcript, November 18, 1997, online at www.ontla.on.ca/hansard/committee_debates/36_parl/session1/hydro/h018.htm. 70. David Lochbaum, “Reactor Safety Margins,” Union of Concerned Scientists, Speech to the American Nuclear Society, June 8, 1998, website http:// www.ucsusa.org/-energy/view.margins.htm. 71. U.S. General Accounting Office, “Nuclear Regulation, Preventing Problem Plants Requires More Effective NRC Action,” letter report, May 1997. U. S. General Accounting Office Testimony Before the Subcommittee on Clean Air, Wetlands, Private Property, and Nuclear Safety, Committee on Environment and Public Works, U.S. Senate, July 30, 1998. website http://www.senate.gov7/~epw/ 105th/jon730a.htm. 72. CT DPUC, Decision issued July 14, 1995, Investigation into the Restructuring of the Electric Industry, Docket No. 94-12-13, p. 20. 73. R. C. Brown and Associates, Inc. “Conclusions and Recommendations,” chapter X, in Final Report of the Focused Audit of the Connecticut Light and Power Company Nuclear Operations, prepared for the CT DPUC, December 31, 1996. CT DPUC Docket No. 96-10-060, Responses to Interrogatories, Box 78508093.

Bibliography A Note on Sources Various reports and financial data of publicly traded companies used here are available on the Securities and Exchange Commission’s website, www. freeedgar.com. News and journal articles referenced are available through general internet searches and specialized search engines, in addition to library collections of publications. In addition to these generally available sources, numerous documents for Northeast Utilities are available through public access to its regulators, particularly the Nuclear Regulatory Commission and the state regulatory commissions. The Nuclear Regulatory Commission has documents in its Washington reading room, on its website, and in microfilm in libraries throughout the country. The Connecticut Department of Public Utility Control provides its decisions and supporting documents on its internet website, and maintains hard copies of documents obtained through interrogatories issued in the case discovery process. Except for a small percentage of documents deemed confidential, this voluminous material is available to researchers. The department’s staff was willing to retrieve boxes of documents from storage and provide assistance with copying, while maintaining a cheerful and helpful attitude. Our thanks to them. Documents of Northeast Utilities 10K filings with the Securities and Exchange Commission, 1985–2001. 10Q filings with the Securities and Exchange Commission, August 13, 1999. 14A, Proxy statements filed with the Securities and Exchange Commission, 1986–2000. “1994 Millstone Horizontal Self-Assessment Report,” December 16, 1994. CT DPUC Docket No. 96-10-060. Responses to Interrogatories. Box 78508082. “Allegations Root Cause Task Group Final Report.” August 1991. CT DPUC Docket No. 96-10-06. Response to Interrogatories, Box 78508100. Annual reports. 1985–99. Assessment Team Report, Millstone Employee Concerns. “Assessment of the Millstone Nuclear Safety Concerns Program.” January 29, 1996. CT DPUC Docket No. 96-10-060. Responses to Interrogatories. Box 78508082. Brothers, Michael to NRC, Licensee Event Report (LER) 96-007-00, for event dated April 3, 1996, submitted May 2, 1996. CT DPUC Docket No. 96-10060. Responses to Interrogatories. Box 78508100. Budget Administration. Underlying Performance Reward Plan, 1993. January 1994. CT DPUC Docket No. 96-10-060. Responses to Interrogatories. Box 78508078.

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Index

Abramson, Barry, 68 accidents. See safety ACR 7007 Report, 90–92 Allen, Howard P., 25, 116n29, 117n30 Atlantic Energy Company, 25 Atomic Energy Act (AEA), 31–32 Atomic Energy Commission, 19, 32 AZP Group, 23, 25–26 Blanch, Paul, 101 Boston Globe, 101, 104 Brown Report, 72–73 Busch, Robert, 67, 85, 100; answers charges, 102; compensation level of, 108 California, xiv, 20, 22–23, 25 capital, 2–3; cost reduction and, 7–8; deregulated markets and, 68; PSNH bid and, 57–61; unrecovered, 70–71. See also investment Central Maine Power, 58 Central Vermont Public Service, 58 Cicchetti, Charles, 11–12 Cilcorp (Illinois), 23 Clear Air Act, 125n5 Clinton administration, 99 competitive strategy, xi–xii, 3; aggressive response and, 10–13; alternative approaches to, 22–26, 86–87; Board of Trustees and, 101–5; in context, 27–30; cost containment and, 7–13, 27–30, 41–45, 64–73 (see also cost containment); deregulation and, 8–9, 22–26; differentiation strategy and, 27; diversification and, 22–26; enhanced risk theory and, 5; excess capacity concerns and, 9–10; failures of, 104–5; financial conditions and, 13–18; focus strategy and, 27; franchise territories and, 7; generation costs and, 7; Improving Station Performance (ISP) program and, 72–73; management effects from, 83–86; management style and, 38–41; market conditions and, 14–15; McKinsey and Company and, 10, 13; mid–1990s and,

64–87; nuclear power system complexity and, 31–35; Performance Enhancement Program (PEP) and, 59–61, 64–66, 72– 75; PG&E and, 26–27; Power of Change approach and, 67–68; price constraints and, 18–21; PSNH bid and, 57–61, 64– 66; PURPA and, 12; validity testing for, 8; vision of future and, 8–10 “Conduct of Nuclear Power Plant Operations” (NRC), 39–40 Connecticut, 2, 4, 28–29; FERC and, 20– 21; franchise territories and, 7; high wholesale rates of, 70; rate cases and, 13; State Assembly of, 99–100 Connecticut Department of Public Utility Control (DPUC), xiii–xiv, 4, 9, 21, 105; cost containment and, 66–67; delayed responses and, 108–9; Millstone nuclear plants and, 49, 57; rate cases and, 42– 43, 126n19; safety policies and, 35 Connecticut Light and Power (CL&P), 115nn.4,6, 116nn.24,25, 119n12; rate cases and, 42–44, 67, 105; as subsidiary, 14 Connecticut Yankee nuclear plant, 9, 106–7 Consolidated Edison, 4, 106–7 Consumers Power (Michigan), 24 Corcoran, W. R., 40 Corporate Responsibility Committee, 102 corrosion, 34, 48–49 cost containment, xi; Annual Report and, 68–69; budget-review procedures and, 64–65; construction and, 16–18, 26–27, 32; delayed responses and, 108–9; deregulation and, 8–9, 18–19; diversification and, 22–25; DPUC and, 21, 66–67; efficiency and, 7–8, 27–28; extended risk strategy and, xii–xiii, 46–47, 111; FBRC and, 65; FERC and, 20–21; fossil plants and, 31; future prices and, 70; generation costs and, 7, 16–17, 31, 69–73; hazard rates and, 28–29; labor and, 35–36; low-cost dominance and, 7–13, 27–30; management effects from, 83–86; Mill-

148 cost containment (cont.) stone Three and, 16; nuclear electric vs. conventional, 16; operating & maintenance (O&M) and, 16–17, 28, 41–45, 65–66, 71–72, 81, 83–86, 118n9; payroll reduction and, 68; Performance Enhancement Program (PEP) and, 64, 66, 72; Power of Change approach and, 67– 68; price constraints and, 18–21, 70; profits from, 69; PURPA and, 12, 20, 70; rate cases and, 42–44; recovery costs and, 106; reduction measures for, 10–13, 27–30; reengineering of, 67, 77–79; regulatory response framework for, 45–53; restarting costs and, 105–6; revision of, 67; safety and, 34–35, 41–45, 108–11; strategy compensation and, 83–86; success of, 80–83; Three Mile Island and, 16; unrecovered capital and, 70–71 Davis-Besse nuclear plant, xi decomissioning, 4 Department of Energy, 17–18 de Planque, E. Gail, 102 deregulation, 8–9, 18–19, 68; DPUC and, 21; effects of, 22–26 Diablo Canyon nuclear plant, xiv, 26–27, 86–87 Dicus, Greta, 102 diversification, 22–26 Dominion Resources, 24, 25, 106, 114n8 Dow Jones Utilities Index, 68 Dresden nuclear plant, 32 Duke Power (North Carolina), 23 Duquesne Light and Power (Pennsylvania), 23 economic issues: competitive strategy and, 22 (see also competitive strategy); diversification and, 22–26; PSNH bid and, 57–61; shutdowns and, 101–2, 104 economic value (EV), 82, 128n59 EEI Financial Conference, 65–66 electric generation. See nuclear power systems Electric Power Research Institute, 48 Ellis, William, 12, 60, 68; compensation of, 84–85; NRC and, 55–56; retirement of, 108 Employee Concerns Assessment Report, 90 Energy Policy Act, 20

INDEX

Energy Resources Group, 67 “enhanced risk” theory, 2, 5 Enron Company, 25 ethics, 37–41 Event Response Team Report, 93–94 Executive Incentive Compensation Program, 83 extended risk strategy, xii–xiii, 46–47, 111 Federal Regulatory Commission (FERC), 20–21 Feigenbaum, Ted, 100, 102 Feinstein, Jonathan, 119n16 Final Safety Analysis Reports (FSARs), 45, 91–92, 94, 129n2 Financial Forecast and Review, 81 Florida Power and Light, 23, 25 forced outages, 33–34, 50, 77–78 fossil fuels, 9, 31–32 Fox, Bernard, 10, 12, 68, 84–85; answers charges, 99–102; compensation level of, 108; criticism of, 102–4; EEI Financial Conference and, 65–66; senior budget committee of, 65 franchise territory, 7 fuel rods, 33 full-core offloads, 88–91 functional requirements specification (FRS), 52–53 function budget review committee (FBRC), 65 Gan, Li, xiv General Accounting Office (GAO), 109, 134n71 Goebel, David, 104 Grisdela, Cynthia, 123n81 Haddam Neck nuclear plant, 60 Harshbarger, Scott, 101 Hartford Light Company, 14 hazard theory, xiv, 126n31, 127n33; extended risk strategy and, 46–47; ordinary strategy and, 46–47; regulatory response framework for, 45–53. See also safety Hechinger, John, 113n6 hydroelectric systems, 32 Improving Station Performance (ISP) program, 72–73

INDEX

independent corrective action verification program (ICAVP), 133n56 Ingrassia, Lawrence, 123n81, 124nn.82,84,85 Institute of Nuclear Power Operations (INPO), 37–38, 47, 79–80, 120n23 interest rates, 17 investment, xii, 3, 107; AZP Group and, 25–26; Con Ed merger and, 4; cost containment results and, 80–82; deregulation effects and, 22–26, 68; diversification and, 22–26; market conditions and, 14–15 (see also markets); PSNH bid and, 57–61, 64–66; shutdowns and, 101–2, 104; stock price gains and, 15; vision of future and, 8–10 Iowa Public Service, 22, 24 Jackson, Shirley Ann, 99 Jensen, Michael, 85 Jersey Central Power and Light Company, 32 Jones, Daniel P., 113n5 Kagan, Robert A., 37, 119n15 Kahn, Alfred, 117n30 Kennan, Elizabeth T., 102 Kenyon, Bruce, 104, 133n56 Komanoff, Charles, 116n19 labor: competitive strategy effects on, 83– 86; costs of, 35–36; Employee Concerns Assessment Report and, 90; engineer concerns and, 88–89, 98–99, 101; LORT and, 75–76; Millstone shutdown and, 48–56; morale and, 49–50; operator training and, 35–36; payroll reduction and, 68; Performance Enhancement Program (PEP) and, 66; stock ownership plan and, 64; whistle-blowers and, 52– 56, 61, 88–89, 98–99, 101, 113n4 LaPorte-Thomas model, 37–38 legal issues, 101, 114n7; criminal charges and, xi; Energy Policy Act and, 20; exclusive franchise territory and, 7; FERC and, 20–21; interstate power transmission and, 19–20; MMWEC suit, 106; Price-Anderson Act, 119n18; PUHCA, 25; PURPA, 12, 20, 114n2; rate cases and, 13; safety violations and, 4 Levy, Paul F., 117n38

149 Licensed Operator Requalification Training (LORT), 75–76 licensing, xi, 18, 39, 88, 105, 113n2; OIG and, 89; Performance Enhancement Program (PEP) and, 64; Seabrook, 59–61, 64, 70, 116n26. See also Systematic Assessment of License Performance (SALP) Long Island Sound, 49 Loss of Coolant Accident (LOCA), 76–77, 107 low-cost dominance. See cost containment LRS Incorporated, 57 maintenance: budget targets and, 83–86; cost containment of, 16–17, 28, 41–45, 65–66, 71–72, 81, 83–86, 118n9; increased standards for, 36; meltdowns and, 33; Millstone shutdown and, 48– 56; NRC and, 35–37; recovery costs and, 106; refueling and, 32 management, xi–xii, xiv, 59; answers charges, 99–101; Board of Trustees and, 2–3, 13, 78–80, 84, 101–6; budgetreview procedures and, 64–65; competitive strategy and, 27–30 (see also competitive strategy); cost containment and, 7, 10–13, 27–30 (see also cost containment); delayed responses and, 108–9; deregulation and, 22–26; Employee Concerns Assessment Report and, 90; extended risk strategy and, 46–47; FBRC and, 65; franchise territories and, 7; INPO and, 37–38; layoffs and, 10; leadership failure of, 101–5; LORT and, 75–76; McKinsey and Company and, 10, 13; Millstone nuclear plants and, 48–56; payroll reduction and, 68; PEP and, 73–75 (see also Performance Enhancement Program); reengineering of, 77–79; regulatory response framework for, 45–53; safety and, 38–41 (see also safety); security and, 6; self–regulation and, 37–38, 42–43; strategy compensation and, 83–86; successes of, 108; top/ down style of, 28; unaccountability of, 108, 111 markets, 69–70; competitive strategy and, 14–15 (see also competitive strategy); deregulation and, 68; diversification and, 22–26; FBRC and, 65; franchise territo-

150 markets (cont.) ries and, 7; gains in, 69; generation costs and, 66; McKinsey and Company and, 30; PSNH bid and, 57–61, 64–66 Massachusetts, 2, 28–29; FERC and, 20– 21; franchise territories and, 7; rate cases and, 13 Massachusetts Municipal Wholesale Electric Company (MMWEC), 106 Mattson, Roger J., 35, 119n12 McKinsey and Company, 10, 13, 21, 25– 26, 29–30, 68 meltdowns, 5, 16, 33 Millstone nuclear plants, xi–xiv, 3–6, 42– 45, 59, 109; age of, 9; Assessment Panel for, 74–75; corrosion and, 48–49; cost reductions and, 11, 44–45; DPUC and, 49, 57; engineer concerns and, 88–89, 98–99, 101; error analysis of, 48–53; expense of, 16, 18; finances of, 61–63; forced outages and, 77–78; FRS and, 52–53; FSARs and, 91–92, 94; full-core offloads and, 88–91; hazard rates of, 28–29; investment in, 15; LRS Incorporated and, 57; Notice of Violations (NOVs) and, 55, 75, 90, 102, 107–8; Nuclear Regulatory Commission and, 3, 19, 48–56; operating performance of, 48–53, 61–63; peening event at, 88; Performance Enhancement Program (PEP) and, 64, 73–74; regulatory response framework for, 46; restarting of, 105–6; safety standards and, 35–36; SALP and, 48–49, 51–54, 62–63; shutdowns of, 48–56, 88–98; Special Review Group and, 55–56; spring 1993 problems of, 75–79; Watch List and, 97–98; watersystem failures and, 48 Minnesota Power and Light, 24 Moody’s Investors, 104 mortgage bonds, 64 Murley, Thomas E., 39, 60 mussels, 49 Nader, Ralph, 120n23 natural gas, 32 NEEC Task Group Report, 57 New England Electric System (NEES), 22, 58 New Hampshire, 13 New York Power Authority, 70

INDEX

Niagara Mohawk, 70 Northeast Utilities, xiv; Annual Report and, 10–13, 65–69, 80–81; Board of Trustees of, 2–3, 13, 78–80, 84, 101–6; charter of, 2–3; collapse of, 1–2; competitive strategy of, xi–xii, 2–30 (see also competitive strategy); cost containment and, 8, 10–13, 41–45 (see also cost containment); electricity sales of, 3; engineer concerns and, 88–89, 98–99, 101; excess capacity concerns and, 9–10; executive compensation of, 83–86; FBRC of, 65; FERC and, 20–21; financial data of, 13– 18, 81–83, 102, 105; fines on, 4; fullcore offloading and, 88–91; historical perspective on, 1–5; Improving Station Performance (ISP) program and, 72–73; increased sales of, 69; layoffs and, 10; leadership failure of, 101–5; LORT and, 75–76; market conditions and, 14–15; McKinsey and Company and, 10, 13, 21, 25–26, 29–30, 68; Millstone shutdown and, 48–56 (see also Millstone nuclear plants); 1988 summer peak and, 9; nuclear power plants of, 17; Nuclear Regulatory Commission and, xi–xiii, 19 (see also Nuclear Regulator Commission); Performance Enhancement Program (PEP) and, 59–61; Power of Change approach and, 67–68; public concern and, 98–101; Public Service bid and, 57–61, 64–66; size of, 13–14; Yankee nuclear plant and, 9 Nuclear Energy Institute, 118n7 Nuclear Engineering and Operations, 10–11 nuclear industry: construction costs and, 7, 16–18, 31, 69–73; deregulation and, 8– 9, 18–26, 68; full-core offloads and, 88– 91; government and, 31–32; INPO and, 37–38; management style and, 38–41; PSNH bid and, 57–61, 64–66; selfregulation and, 37–38; Watch List and, 36–37 nuclear power systems: Atomic Energy Act (AEA) and, 31–32; complexity of, 31–35; construction times for, 32; corrosion and, 34, 48–49; forced outages and, 33–34; 50, 77–78; FRS and, 52–53; generation costs and, 7, 16–17, 31, 69–73; refueling and, 33; standard design for, 32–33

INDEX

Nuclear Quality and Assessment Services, 76–77 Nuclear Regulatory Commission, xi–xiv, 2, 28; abnormal occurrences and, 35; Design Basis Reconstruction Program and, 57; fines by, 75; FSARs and, 45, 91–92; full–core offloads and, 88–91; human error and, 35; increased standards of, 18–19, 35–37; INPO and, 38; Millstone nuclear plants and, 3, 19, 48–56; Notice of Violations (NOVs) and, 55, 75, 90, 102, 107–8, 127n33, 129n3; Office of Nuclear Reactor Regulation and, 39; Performance Enhancement Program (PEP) and, 59–61; price constraints and, 18–19; public concern over, 98–101; regulatory response framework for, 46; reputation of, 107–8; safety criteria by, 35–37 (see also safety); SALP and, 36, 39, 48–49, 51–56, 75–79 (see also Systematic Assessment of License Performance); Seabrook licensing and, 59–61, 64, 70, 116n26; Special Review Group and, 55–56; Three Mile Island and, 5; Watch List of, 36–37, 88, 90, 97–98, 106, 108, 130n18 Office of Inspector General (OIG), 89 Office of Nuclear Reactor Regulation, 39, 60 oil, 16 Opeka, J. F., 65, 85, 108 operator training, 35–36 ordinary strategy, xii–xiii, 46–47 Oyster Creek plant, 32 Pacific Gas and Electric (PG&E): Diablo Canyon plant of, xiv, 26–27, 86–87; diversification and, 22, 24 Pacificorp, 23 Pate, W. J., 102–3 Peach Bottom nuclear plants, 80, 128n56 peening event, 88 Pennsylvania, 22, 70, 79–80 Pennsylvania Power and Light, 24, 70 Performance Enhancement Program (PEP), 59–61, 87, 110, 126n22; Board of Trustees and, 78–80; Brown Report and, 72–73; budget-review procedures and, 64–65; closeout report on, 94; cost containment and, 66, 71–72; description of, 73–75; Improving Station Performance

151 (ISP) program and, 72–73; increased staff from, 66; Millstone issues and, 75– 79; outlays for, 66; payroll reduction and, 68; phases of, 73 Performance Reward Plan, 83–84 Perin, Constance, 32 Philadelphia Electric, 79–80 policies, 27–30; Atomic Energy Act (AEA), 31–32; cost containment and, 10–13; diversification and, 22–26; DPUC and, xiii–xiv; Energy Policy Act and, 20; Improving Station Performance (ISP) program and, 72–73; Millstone shutdown and, 48–56; NRC and, xiii–xiv (see also Nuclear Regulatory Commission); Performance Enhancement Program (PEP) and, 59–61, 72–75; process reengineering and, 67, 77–79; PURPA and, 20; regulatory response framework, 45–53; safety and, 35 (see also safety) Porter, Michael, 27 “Power of Change, The” (report), 67–68 Price-Anderson Act, 119n18 prices, 2–3, 28–29; Con Ed merger and, 4; constraints of, 18–21; cost reduction and, 7–8; deregulation and, 68; DPUC hearings and, 66–67; FERC and, 20–21; future, 69–70; market conditions and, 14–15; nuclear electric vs. conventional, 16; Nuclear Regulatory Commission and, 18–19; oil, 16; Performance Enhancement Program (PEP) and, 66; PURPA and, 20; rate cases and, 13, 42– 44, 67, 105, 117n37, 126n19; regulation and, 11–12; safety and, 18–21 process reengineering, 67, 77–79 productivity: cost reduction and, 7–8, 10– 13; data for, 13–18; deregulation and, 8–9; Performance Enhancement Program (PEP) and, 72–75; price constraints and, 18–21; process reengineering and, 67, 77–79; safety and, xi, 38–41 profits, 2, 113n1; cost containment and, 7–8, 69, 80–82 (see also cost containment); data for, 13–18; deregulation and, 8–9; DPUC hearings and, 66–67; McKinsey and Company and, 30; Performance Enhancement Program (PEP) and, 66; rate cases and, 42–44; shutdowns and, 3–4, 101–2, 104–5. See also competitive strategy

152 public concern, 98–101, 107–8 Public Service of New Hampshire, 13, 115n7; Northeast Utilities bid on, 57– 61, 64–66 Public Utilities Regulatory Policies Act (PURPA), 12, 20, 70, 114n2 Public Utility Holding Company Act (PUHCA), 25 Quinn, M. D., 94 radiation, 32–33 rate base, 13, 42–44, 67, 105, 117n37, 126n19 R. C. Brown and Associates, 109, 114n9, 126n20, 127n45, 134n73; Board of Trustees strategy and, 79; management compensation and, 83–84; NU’s business plan analysis by, 72–73, 79 reactor core: forced outages and, 33–34, 50, 77–78; full-core offload and, 88–91; sensor systems for, 34 recovery costs, 106 refueling, 33 regulation, 2, 32; ACR 7007 Report and, 90–92; cost containment and, 31, 41– 45; deregulation and, 18–19, 21–26, 68; DPUC and, xiii–xiv, 21 (see also Connecticut Department of Public Utility Control); FERC and, 20–21; franchise territories and, 7; INPO and, 37–38; interstate power transmission and, 19–20; LaPorte-Thomas model of, 37–38; licensing and, xi, 18, 39, 59–61; LRS Incorporated and, 57; maintenance and, 35–37; Millstone event and, 3, 48–56; Notice of Violations (NOVs) and, 55, 75, 90, 102, 107–8, 127n33, 129n3; NRC and, xiii–xiv, 18–19, 35–37 (see also Nuclear Regulatory Commission); Performance Enhancement Program (PEP) and, 64; price constraints and, 18– 21; PUHCA, 25; PURPA and, 12, 20; rate increases and, 11–12; response framework for, 45–53; self-regulation and, 37–38, 42–43, 50–51, 131n31; Watch List and, 36–37, 88, 90, 97–98, 106, 108, 130n18 Remick, Forrest J., 60 risk management, 7; cost vs. safety and, 108–11; enhanced risk theory and, 5; ex-

INDEX

tended risk strategy and, 46–47; fullcore offload and, 88–89; ordinary strategy and, 46–47. See also management Rothwell, Geoffrey, 121n52 safety, 2, 4, 84; abnormal occurrences and, 35; ACR 7007 Report and, 90–92; automation of, 34; corrosion and, 34, 48–49; cost containment and, 34–35, 41–45, 108–11; delayed responses and, 108–9; design approach and, 33–34, 39–40; Employee Concerns Assessment Report and, 90; engineer concerns and, 88–89, 98–99, 101; forced outages and, 33–34, 50, 77–78; FSARs and, 45, 91– 92, 94, 129n2; full-core offloads and, 88–91; hazard rates and, 28–29; human error and, 35; INPO and, 37–38; LOCAs and, 76–77, 107; LORT and, 75–76; management and, 38–41; meltdowns and, 5, 16, 33; Millstone and, 48–56 (see also Millstone nuclear plants); Notice of Violations (NOVs) and, 55, 75, 90, 102, 107–8, 127n33, 129n3; NRC and, 18–19 (see also Nuclear Regulatory Commission); overlapping systems for, 33–34; price constraints and, 18–21; public concern and, 98–101, 107–8; radiation and, 32–33; regulatory margin and, 38–39; response framework for, 45–53; SALP and, 36, 39, 48–49, 51–56; security and, 6; selfregulation and, 37–38; sensor systems for, 34; shutdowns and, 33–34, 40 (see also shutdowns); steam accidents, 32; subjective judgment and, 33; Three Mile Island and, 5, 16, 33–34, 45, 118n8, 121n52; valves and, 35, 76, 92–93, 132n46; Watch List and, 36–37, 88, 90, 97–98, 106, 108, 130n18; whistleblowers and, 52–56, 61, 88–89, 98–99, 101, 113n4 San Diego Gas and Electric, 25 Sawhill, John, 25 Scholz, John T., 119n15 Seabrook nuclear plant, 59–61, 64, 70, 116n26 security, 6 self-regulation, 37–38, 42–43, 50–51, 131n31 September 11, 2001, xiii

153

INDEX

SEV function, 46–47, 111 Shippingport nuclear plant, 32 shutdowns, 62, 77–78, 124n92; economic effects of, 101–2; extended risk strategy and, 46–47; FSARs and, 91–92; Millstone nuclear plants and, 48–56, 88–98; ordinary strategy and, 46–47; profits and, 101–2, 104–5; regulatory response framework for, 45–53; strategy cause of, 108–11; technology for, 33–34, 40 Social Science Research Network (SSRN), xiv Southern California Edison, 22, 25 Standard and Poor’s, 104 steam accidents, 32 “Strategy to Meet Competitive Threat” (Fox), 10, 65–66 Surry Nuclear Power Plant, 48 Systematic Assessment of License Performance (SALP), 36, 39, 53–56, 122n64, 127n42; LORT and, 75–76; Millstone nuclear plants and, 48–49, 51–52, 62–63, 74–79; Performance Enhancement Program (PEP) and, 74–79 tariffs, 2 Taylor, James, 80, 98 technology: automation, 34; cooling of core and, 33; fossil fuels and, 31–32; fuel rods and, 33; nuclear power complexity and, 31–35; shutdown, 33–34, 40 Texas, xiv

Three Mile Island, 5, 16, 33–34, 45, 118n8, 121n52 Time magazine, 98–99 United Illuminating Company, 58–59 Updated Final Safety Analysis Report (UFSAR), 88, 100–101 utilities: corporate strategies of, 22–26; cost reduction and, 7–8; deregulation and, 8–9, 18–19, 22–26 (see also regulation); Dow Jones Index and, 68; franchise territories and, 7; 1988 summer peak and, 9; PG&E and, 26–27; policies and, xiii–xiv (see also policies); PSNH bid and, 57–61, 64–66; PURPA and, 12; supply substitution and, 9–10. See also Northeast Utilities valves, 35, 76, 92–93, 132n46 Wald, Matthew, 116n26 Wall Street Journal, 102–3 Watch List, 36–37, 88, 90, 97–98, 106, 108, 130n18 water systems, 48–49, 93 Western Massachusetts Electric Company, 14 whistle-blowers, 52–56, 61, 113n4; engineers and, 88–89, 98–99, 101 Wiggins, James T., 74 Wisconsin Electric Power, 23 Wood, William C., 119nn.17,18 Zausner, Eric, 65