Privatization and Restructuring of Electricity Provision (Privatizing Government: An Interdisciplinary Series)

PRIVATIZATION AND RESTRUCTURING OF ELECTRICITY PROVISION

Recent Titles in Privatizing Government: An Interdisciplinary Series Privatizing Education and Educational Choice: Concepts, Plans, and Experiences Simon Hakim, Paul Seidenstat, and Gary W. Bowman, editors Privatizing Transportation Systems Simon Hakim, Paul Seidenstat, and Gary W. Bowman, editors Privatization and Competition in Telecommunications: International Developments Daniel J. Ryan, editor Restructuring State and Local Services: Ideas, Proposals, and Experiments Arnold H. Raphaelson, editor Smart Contracting for Local Government Services: Processes and Experience Kevin Lavery

PRIVATIZATION AND RESTRUCTURING OF ELECTRICITY PROVISION Daniel Czamanski

Privatizing Government: An Interdisciplinary Series Simon Hakim and Gary Bowman, Series Advisers

PRAEGER

Westport, Connecticut London

Library of Congress Cataloging-in-Publication Data Czamanski, Daniel Z. Privatization and restructuring of electricity provision / Daniel Czamanski. p. cm. — (Privatizing government, ISSN 1087-5603) Includes bibliographical references and index. ISBN 0-275-95687-3 (alk. paper) 1. Electric utilities—Deregulation. 2. Privatization. I. Title. II. Series. HD9685.A2C95 1999 333.793"2'0973—dc21 98-41088 British Library Cataloguing in Publication Data is available. Copyright © 1999 by Daniel Czamanski All rights reserved. No portion of this book may be reproduced, by any process or technique, without the express written consent of the publisher. Library of Congress Catalog Card Number: 98-41088 ISBN: 0-275-95687-3 ISSN: 1087-5603 First published in 1999 Praeger Publishers, 88 Post Road West, Westport, CT 06881 An imprint of Greenwood Publishing Group, Inc. www.praeger.com Printed in the United States of America

@r The paper used in this book complies with the Permanent Paper Standard issued by the National Information Standards Organization (Z39.48-1984). 10 987654321 Every reasonable effort has been made to trace the owners of copyright materials in this book, but in some instances this has proven impossible. The author and publisher will be glad to receive information leading to more complete acknowledgments in subsequent printings of the book and in the meantime extend their apologies for any omissions.

Again to Sherry

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Contents

1 2 3 4 5 6 7 8

Illustrations Preface The Privatization Issue—Objectives The Technology of Producing and Managing Electric Systems Political and Economic Constraints Electric Thatcherism in the United Kingdom Israel Incremental Restructuring in the United States The World Beyond Concluding Remarks Appendix Bibliography Index

ix xi 1 15 25 39 63 81 107 127 133 143 149

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Illustrations

TABLES 1.1 Average Price of Domestically Consumed Electricity— Dollars per kwh, Selected Countries, Latest Available Years 1.2 Sales and Average Line-Losses as a Percentage of Net Production—Selected Countries in 1995 1.3 Examples of Structures of Electric Systems 3.1 Classification of Incentive Mechanisms 4.1 U.K. Final Energy Consumption 4.2 Transmission System Performance Prior to Restructuring 4.3 Electricity Generation in England and Wales, 1996 4.4 U.K. Electricity Consumers by Type, 1990 4.5 Net Capacity and Output of Hydro-Electric and Scottish Power, 1990 to 1991 4.6 Net Capacity and Share of the United Kingdom, January 1996 4.7 Hypothetical Industrial Customers 4.8 Typical Prices for Hypothetical Industrial Customers, Selected Years

5 8 13 33 42 48 49 50 54 55 58 58

Illustrations

X

4.9 Typical Prices for Hypothetical Industrial Customers, Selected Countries, 1996 4.10 Takeover Bids for RECs; Status as of December 1996 5.1 Basic Statistics of IEC, Pre-Restructuring Years 5.2 Israel—Some Basic Statistics 5.3 Israel—Electricity Consumption and GNP, Recent Years 5.4 Installed Capacity by Power Station and Year 5.5 Average Tariffs and Projected Consumption Growth Rates 6.1 Average Yearly Electricity Prices in Ohio 6.2 Selected Financial Indicators, U.S. Electric Industry 7.1 Electricity Consumption, 1996, and Liberalized Share in EU Countries 7.2 Typical Monthly Electricity Costs in Canada by Location, 1994 7.3 Population Connected to Electricity in Developing Countries

59 60 65 66 67 68 70 84 85 109 121 125

FIGURES 2.1 2.2 3.1 4.1 4.2 4.3 5.1 5.2 5.3 A. 1

Schematic of a Simple Electric Power System Incremental Cost Curves for a Hypothetical System The Central Actors in the Electricity Sector The Electricity System in the United Kingdom before 1989 The Electricity Industry in the United Kingdom after 1990 Electricity Flows in the United Kingdom after 1990 Proposed Structure of Israel's Electricity System—Intermediate Stage Proposed Structure of Israel's Electricity System—Year 2000 Schematic Structure of Israel's Electricity Law, 1996 The Profit Function of a Firm, Subject to a Rate-of-Return Constraint

16 20 27 41 43 44 74 75 79 135

A.2 Responses to Tightening Rate-of-Return Constraint

137

A.3 Manager's Equilibrium

140

A.4 Regulator's Optimum

142

Preface

My interest in the electricity industry and in mechanisms designed to improve its efficiency goes back to the early years following the energy crisis that began soon after 1973. Oil shortage, followed by natural gas shortage, affected electricity production and electricity consumption patterns. High electricity bills in the United States caused by electric home heating created public awareness of electricity prices. Financial difficulties of many utilities and the need to restructure declining block rate structures led to an intense debate among utility economists. The efficiency of the industry has become part of general public concern. The implementation of the Public Utility Regulatory Policies Act and my employment as an economist at the newly established National Regulatory Research Institute (NRRI), the research arm of all the regulatory commissions in the United States, created for me an opportunity to think about alternate regulatory regimes to promote efficiency. At the NRRI, I was fortunate to have two intellectually stimulating colleagues, Kevin A. Kelly, a nuclear engineer, and J. Stephen Henderson, a fellow economist. Several years of work together, and an endless stream of formal and informal discussions and debates that focused on the engineering and economics aspects of the various issues of electricity reforms, taught me that public policy making and implementation requires a deep understanding of practical and technical issues alongside a keen theoretical backdrop, one's interests notwithstanding.

Xll

Preface

In the early 1990s, I was fortunate enough to be appointed as an economic advisor to Israel's Minister of Energy, Amnon Rubinstein, and to be charged with preparing legislation intended to create an electric industry for the twentyfirst century. As a preparation for the task, I undertook to learn the state of the thinking and the actions being taken in a variety of countries. Again I was very fortunate to spend some very fruitful time with many very knowledgeable individuals. I cannot list all those who devoted their time to me. They include executives and engineers in electric companies throughout the United States, Canada, and Europe, government ministers, bankers, and regulators. Two individuals made a special contribution to my understanding of the industry: Ralph Turvey, whose phenomenal understanding of the industry is matched only by his understanding of wines, and Ian Moen, the regulator of the Norwegian electric industry. Both individuals led me to understand that truly farreaching reforms are incremental in scope, and they require as a prerequisite the preparation of institutions that make them work. Finally, I had the great fortune to debate electricity reforms endlessly with a group of top executives at the Israel Electric Corporation. Alas, some of them have left the corporation and are making their first brave steps in the private world. Among these are Moshe Katcz, who served as the CEO of the company, Moshe Lasry, its chief engineer, and Yigal Porath, its director of R&D. Others that remain at the Israel Electric Corporation are Yaakov Razon and Shmaryahu Bratt. My personal friend, Namir Yahya, of the Israel Oil Refining Company, heard my ideas endlessly, never refusing to be a sounding board and a good technical counsel. I am thankful to the Techncion-Israel Institute of Technology for providing me with a care-free environment in which it was possible to pursue one's intellectual fancy. In this respect, I am grateful to my dean, Daniel Shefer who on numerous occasions over the last two years was willing to accept my refusal to partake in public service activities so that I could devote the requisite time to this book. I am particularly thankful to the editor of this series, Simon Hakim, who asked me to undertake this adventure and to take time out to make some intellectual order in a very complex world. It was a rare treat to ask my father, Stan Czamanski, to read the manuscript and to receive his comments, both insightful and useful. Without implicating him in the remaining faults of this book, I am very grateful to him for his effort to improve it. Finally, a truly personal note. I have been extremely fortunate to share the last thirty years of my life with a companion who was willing to give of herself so that I could pursue my fancy, be it a career or a lifestyle, a pursuit that at times seemed to have taken us to difficult, nay, truly dangerous, places. The myriad of friends who know Sherry well seek her company for advice, companionship, and above all, for calm—just as I do. Her devotion to others is famous. It was apparent to all when, during the Gulf War, while many fled Israel as a protection from scud attacks, Sherry cut short her stay in Canada and was the only civilian on a plane returning to Israel to be with her family during a truly difficult time. I have heard of no daughter-in-law who would fly across the ocean to tend her in-laws so that her husband need not interrupt his work.

1 The Privatization Issue—Objectives

It is hard to imagine a world without electricity. We take it for granted that all buildings in which we live, work, and spend our leisure hours are connected by wires to some distant source of electric energy. Even open public spaces, such as streets, parks, and parking lots, are provided with electricity. We expect all such places to have adequate lighting and to be properly heated, cooled, and ventilated as the need arises. It is equally hard to imagine a modern economy without electricity. Could we function without computerized production? Indeed, electricity has been supplied to households and to places of work before we were born. Like the supply of daily bread and other essential products in the local grocery store, electricity is expected to arrive at the point of consumption and at a turn of a switch to make our modern lives not only bearable, but enjoyable. An "invisible hand" ensures that our electricity needs are provided for on call. Our expectations go much further than that. We expect the cost of consuming electricity to be bearable, even for those who happen to be at the lower end of the income scale. In the modern world, electricity is not considered a luxury good. It is a necessity. Easy and affordable, accessibility to the grid is considered to be so essential that in the mid-1970s special electricity rates ("lifeline rates") were implemented to ensure accessibility to all, even to those who cannot afford it (Kelly et al. 1976).

2

Privatization and Restructuring of Electricity Provision

In general, we do not stop to think about electricity. We do not ask what constitutes this product, what range of electric services are provided in the electric package, from where electricity is moved to our doorstep, how it is produced, and who and how determines its price. It is the relatively rare stoppage of service, especially the prolonged blackout like the famous New York City blackout of 1965, that shocks us into realizing that electricity is not only a product and service, but a complex industry that includes a surprising variety of players with a diversified range of interests. Owners of power plants that produce electrons by various technologies, and owners of the wires that transmit and distribute them to dispersed points of consumption, are interested in high return on their investments. Banks that loan money to the industry are interested in the stability of revenues so as to ensure repayment of their loans. Also, the many workers who are employed by the industry have the stability of employment and income as a distinct interest. Occasionally, organized labor in the electricity industry, because of their sheer numbers, have become a political force with a much broader set of interests. Obviously, the various consumer groups (among them, large industrial, small industrial, commercial, and household consumers) have interests that include the stability and quality of service and low electricity bills. The coordinating frameworks within which these interests interact in the different systems and thus provide us with this essential product and its related services are far from being uniform. In no country is it a simple mechanism. Frameworks range from government-owned monopolies to a mixed system of privately and publicly-owned monopolies and competing producers. All are regulated through a variety of historically determined institutions that set the rules of the game. Furthermore, the system is in flux. In some countries, government-owned, vertically integrated monopolies will continue to be the sole providers of electricity in the foreseeable future. The various interests will not interact freely to determine their mutual futures. In other countries, definite steps are being taken to make them interact through markets. Competition, instead of benevolence or regulation, will discipline the actors and prevent excessive power to the disadvantage of the weaker players. Even in the largely private systems, such as those in the United States, large components of the system remain in the hands of governments. In many systems, privatization has become the major component of electricity reforms. Electricity reforms, including privatization, have become a topic of conversation throughout the world. Electricity supply consists of a product and of a service. l Electrons that constitute the product are an amazingly homogeneous entity. Indeed, once they are produced and pushed into the grid, they are indistinguishable from each other. This is despite the fact that there exist numerous technologies for producing electrons, and that the actual methods used to produce the product differ greatly among the world's electricity systems. This is true even within a particular system. Nuclear, hydroelectric, and coal-fired, base-load

3

The Privatization Issue

plants coexist with combined-cycle natural gas and other fuels intermediate and peaking plants. Most systems are quite diversified and include a mixture of plants. Furthermore, most electricity supply systems are interconnected, at least partially. As a result, shortage of electrons in one system can be compensated for, at least in theory, by additional production within a neighboring system. Since the product is interchangeable and the interconnection of systems permits movement of product across systems, it is surprising that all inefficiency is not wiped out. Presumably, only the isolated (i.e., not interconnected systems) should remain bastions of inefficiency. Common sense suggests that consumption of electricity depends on such factors as income levels, industrial structure of places, or geography. Similar places should display similar consumption patterns. For the same reason that the world consumes hamburgers and cola for lunch, all other things being equal, we should expect similar patterns of electricity consumption across systems. Moreover, even in the case of the isolated systems, it is to be expected that inefficiently managed companies will not survive. Very often the same institutional investors own parts, or entire, neighboring systems. Should we not expect that the inefficient managements would be replaced by the more capable and efficient managements? INEFFICIENCY Electricity systems may display both allocative and technical inefficiency. Allocative inefficiency is present when the baskets of goods and services produced in an economy does not match those preferred by the consumers. Often such a condition occurs when prices do not reflect marginal costs, and the independent consumption decisions lead to overconsumption of some products and the underconsumption of others. In the ideal, textbook world as described so eloquently by Lerner's doctoral dissertation and book (1944), the efficient basket of goods and services that an economy produces and consumes is characterized by an equality between the benefits and costs that are yielded to society by one additional unit produced and consumed. The presence of equality between marginal social benefits (MSB) and marginal social costs (MSC) in the case of all products and services ensures an efficient allocation of society's scarce resources: MSB = MSC Under some circumstances, such an equality can be achieved almost automatically by the free interactions of consumers and producers. In their attempt to secure highest personal benefits, self-interested and fully informed consumers select products and services so as to equate personal benefits or marginal utility (MU) with the price of the product (P), which is the amount of

4

Privatization and Restructuring of Electricity Provision

money that must be parted with to secure the exclusive rights to the marginal unit of the product or service: MU = P It is natural that the rational consumer allocates her limited budget and selects the basket of goods and services by comparing the benefits foregone of alternate consumption baskets. In other words, consumers examine the opportunity costs of their decisions. In a similar fashion, producers of products and providers of services, interested as they are in profit maximization, seek to equate their marginal revenue from selling the marginal unit with the marginal cost (MC) of making it available. In a world characterized by free competition, in which no supplier has excessive influence on the product's price, the market-determined price of the product represents the product's marginal revenue. Thus it is obtained that P = MC The invisible hand of Adam Smith leads the market economy to allocate resources and to produce and consume a basket of goods and services that is characterized by MU = P = MC In addition to the requirements that the interactions in the marketplace be free and unhindered and that the economic agents be self-interested and rational, this normative model requires that the sums of all personal benefits and of all private costs do not exceed or fall short of the sums that accrue to society. Not taking into account external unpriced influences in consumption and production (i.e., externalities) or by assuming the existence of appropriate regulatory mechanisms, the market mechanism can provide the basis for defining an efficient allocation of resources in terms of MSB = MU = P = MC = MSC Self-interests and market-determined prices ensure that products are produced at minimum cost by combining factors of production in the most technically efficient manner. The same forces ensure that allocative efficiency is achieved and that we do not over or under consume products and services. In the case of electricity, it is the surprising and unjustified variance in the average price paid by consumers of electricity in different countries that indicates the presence of allocative inefficiency (see Table 1.1). When one considers the vastness of investments in the power stations that are used to produce electrons and in the wires used to transmit and distribute them to the many

5

The Privatization Issue Table 1.1 Average Price of Domestically Consumed Electricity—Dollars per kwh, Selected Countries, Latest Available Years Country

1994

1993

Japan

.210

.190

Germany

.190

.190

Belgium

.185

.197

France

.169

.177

Denmark

.161

.182

Italy

.161

.143

Spain

.160

.193

Austria

.160

.171

Portugal

.158

.184

Great Britain

.133

.141

Holland

.120

.125

Ireland

.117

.135

Greece

.100

.116

Sweden

.096

.111

Israel

.092

.092

United States

.089

.105

Finland

.084

.092

Australia

.081

.081

Canada

.076

.077

South Africa

.073

.073

New Zealand

.064

.058

Source: Unipede Electricity Statistics, May 24, 1996 (www.unipede.org).

points of consumption, it is reasonable to assume that the price differences stem principally from variations in production and distribution efficiency. It is difficult to fathom that service quality differences account for a significant portion of the variance in the price to consumers. Simply said, these other costs account for a very small fraction of the total cost of delivering the prod-

6

Privatization and Restructuring of Electricity Provision

uct and providing all related services. Even when one corrects for the fact that prices in the different places reflect also differences in exchange rates and differences in local buying power, it is impossible not to be impressed by the vast range in the resulting prices. As an example, in 1994, households in Japan paid more than three times as much per kwh of electricity than households in New Zealand. New Zealand has abundant hydroelectric plants, a resource that enables it to use a very inexpensive technology in producing electrons. The low running costs compensate for the great capital investments in hydro plants and for the great cost of moving electrons from the distant points of production to the various points of consumption. A similar situation exists in Canada. In order to avoid unfair judgments concerning performance, it is advisable to compare groups of countries with similarly diversified production technologies. Still, the price differences are impressive: U.S. households pay half as much as households in western Europe. Can it be that differences in the nature of the services offered by electricity systems account for the differences in price? Looking at a broader range of countries than the developed world, the extremes become even more apparent. It turns out that, as a rule, the price of electricity is an inexact indicator of the cost of the product consumed and of the services provided. Prices are often a reflection of subsidies and not of the true costs of producing and providing the service. In many countries, not all the costs of producing and delivering electricity are passed on to consumers. In Israel, for example, the land used to transmit and distribute electricity is government-owned and freely provided to the state-owned monopoly. The dividends paid to governments as sole owners of electric utilities do not always reflect the price of capital, properly adjusted for risk. In many countries, prices for the current year are set on the basis of historic costs. In a world with even a moderate rate of inflation, the resulting subsidies are enormous. Since the cost of delivering electricity varies by voltage, time of day, season, and location, the use of average price to all consumers at all times hides an additional and significant subsidy. Inefficiency permeates many electric systems. Consumption patterns are wasteful in the sense that preferences over types of electricity (defined in terms of quality) do not match actual consumption, which is constrained by supply characteristics. Uncontrolled or inefficient amounts consumed and time of consumption cause exaggerated investments in capacity, overuse of often imported energy and environmental degradation. While in some countries it has been possible and common to reduce per capita consumption of energy without affecting adversely economic performance, in other countries per capita consumption continues to grow. Thus, for example, the per capita consumption of energy in the United States in the mid-1990s has decreased to under 95 percent of the preenergy crisis year 1973. During the same period, OECD countries increased per capita consumption by more than 6 percent, the European Community (EC) countries by 11 percent, and Japan and Israel by about 25 percent. Inevitably, both allocative and technical inefficiencies are prevalent.

The Privatization Issue

7

Would it not be reasonable to assume, therefore, that over time the inefficient systems would have been forced to improve and to adjust to the standards set by the more advanced countries? Improved efficiency is in the interest of all consumers. It is of particular interest to exporters of electricity-intensive products competing in the world markets. In an electric world that is characterized by a significant degree of interconnections, it is to be expected that the inefficient producers would be priced out. In theory at least, cheaper electrons could be moved to countries that fail to reduce the cost of delivering electricity to a minimum. In the presence of globally active, multinational electric companies, it should be expected that the inefficient producers will be taken over by more efficient managements. Though there are no technologically or institutionally determined imperatives that prevent improvements, the actual situation is much worse. There are many countries that still fail to provide electricity to all of their citizens. In the mid-1990s, Thailand served only 80 percent of its population. The World Bank (1994) set a target of "ninety percent of the population served" as a credible goal for many countries. Yet, even such countries as Argentina, which has connected all of its population to the grid, does not provide electricity at all times. The average number of hours of blackouts varies greatly among places. In the mid-1990s, Thailand stood at seventy-two hours per year, Argentina at twenty-four hours per year, and Israel at ten hours per year; seven hours per year seemed a reasonable target to be set by the World Bank. Brownouts, or partial blackouts, are a daily event in very many countries. These then are indicators of the prevalent technical inefficiency, a situation characterized by nonmaximal exploitation of the resources actually used by electric systems. With the particular basket of land, capital, labor, and energy, it could be possible to produce and deliver more electrons to the final consumer. Alternatively, the particular basket of final products could have been supplied with a smaller amount of inputs. Although labor costs are not the dominant cost component of electricity, the number of customers per employee is a telling indicator of system management efficiency. In the mid-1990s, in Pakistan it stood at 38 customers per worker, Argentina 126 customers per worker, and Thailand at 150. In the United States, the average is 145. Henney (1971) has estimated that a similar coal-fired generating plant with installed capacity of 200 MW was staffed with 844 people in the preprivatized U.K. system, and 500 in a privately owned U.S. company. Average line-losses in the system is another indicator of system efficiency. Table 1.2 presents sales and average line-losses for selected systems. Again, the significant variance is noteworthy. Here also, there are some mitigating circumstances. The geographic size and geographic and electric topography of systems explain only in part the apparent differences. Clearly, the efficiency of the various systems does not approach uniformity. In electric systems dominated by public sector ownership, privatization is deemed as a worthy means to improve efficiency. Regulation alone has been

8

Privatization and Restructuring of Electricity Provision Table 1.2 Sales and Average Line-Losses as a Percentage of Net Production— Selected Countries in 1995 Country

Sales

Line-losses

Algeria

78.1

16.2

Poland

81.9

13.7

Romania

91.2

10.3

Great Britain

96.2

8.6

Spain

93.1

8.3

107.4

7.8

Norway

91.2

7.4

Sweden

93.8

6.2

Japan

92.7

5.8

Belgium

98.8

5.4

Tunisia

100.5

4.8

Italy

Israel

95.8

4.5

Germany

95.0

4.4

Holland

109.4

4.4

Finland

105.8

4.0

Source: Unipede Electricity Statistics, May 24, 1996 (www.unipede.org).

judged incapable of improving the extant conditions. But, interest in the privatization of electricity supply is motivated also by the need to expand the world system. In many countries, historic sources of government-provided finance are simply not available. By the year 2000 there will be a need to install over 500 hundreds of gigawatts of required plant capacity outside the United States to meet the demand, at current levels of consumption. The following countries will require new power plant capacity by the year 2000.2 World Total in Gigawatts Africa Brazil China Eastern Europe FSU India

545 25 30 100 15 29 55

9

The Privatization Issue

Japan Middle East Other Asia Other Latin America Western Europe

50 50 50 42 99

The investment required for this task is estimated at some U.S. $700 billion. To provide the needed finance, the role of private capital and of the regulatory regime need to be very clearly defined. Need for privately provided equity and debt finance has spawned debate concerning the conditions required in order to make private sector risks bearable. While in the developed economies business risks are well mapped out, in the developing economies conditions are far from being clear. PRIVATIZATION This book is not concerned with finding an explanation for the apparent diversity. Rather, its objective is to critically map out one set of complex policies that are increasingly adopted to mitigate the existing conditions. This is not a "how-to" book. It is not concerned with the way that privatization of electric utilities is executed, what is good or bad about the privatization stateof-the-art, or how it can be carried out better. Rather, it is concerned with the decision-making processes to privatize the electricity supply of a country, state, city, or cooperative group. It is concerned with the process of changing the rules by which decisions about the supply of electricity provision are made. It is concerned with motives of individuals and groups. It is concerned with the strategic and tactical arguments that are at the backdrop and foreground of public debates concerning electricity privatization. It is concerned with interests and the way that these are resolved in the public arena. Because this book focuses on the supply of electricity, it emphasizes the special and unique aspects of this particular industry. The formidable variety of approaches to the emerging issues in different places on the globe suggests that local conditions play a crucially important role in the way that industry characteristics and political conditions interact to create public decisions. As such, the electricity industry provides an interesting stage on which to explore some fundamental public decision-making processes concerning the industrial organization of modern economies. The constellation of extant technologies, historical decisions, and embedded economic as well as political interests make for a variety of mosaics on which to explore the common and the unique. The term privatization, according to the Oxford English Dictionary is of rather recent vintage. In the economic context, it was used first in the 1960s and 1970s to describe the selling of state-owned assets, or state-owned enterprises (SOEs), to private interests. In the United States and Canada, it is used

10

Privatization and Restructuring of Electricity Provision

to describe the act of allowing private enterprises to perform public sector services. This broad usage is not relevant for our purpose in this book, because it refers, for example, to the private removal of municipal garbage or private maintenance of urban public gardens. According to the International Bank for Reconstruction and Development (1995), SOEs are government-controlled commercial entities whose revenues are generated from selling goods and services. They include enterprises controlled directly by government departments and those controlled indirectly through other SOEs. The control can be by virtue of the holding by government of majority shares or shares that entitle the government to effective control. Privatization entails divestiture of the controlling shares in the SOEs. In this sense, privatization began in earnest in the 1980s during the Thatcher government in Great Britain. Since then, governments everywhere have begun to sell off SOEs. No exact data exist to characterize the extent and nature of privatization efforts, yet, according to the International Bank for Reconstruction and Development (1995) study, from 1988 to 1993, there were six times as many divestiture transactions as in the years 1980 to 1987. Though much of this activity followed the restructuring in the former Soviet block countries, 86 percent of the privatization that took place was accounted for by developing countries. More important, about one-third of the revenues generated by divestiture in developing countries during this period originated in infrastructure, including electric, water, transportation, and telecommunications utilities. But even more important, the volume and nature of privatization activities is extremely heterogeneous. There is a need to distinguish between simple private financing of government-owned new capacity, and buy-own-operate (or BOO) and buy-own-operate-transfer (or BOOT) arrangements. In Latin America, privatization of electricity generation facilities has been widespread. For example, Argentina has been a leader in the privatization of electric power, as it was in petroleum. Latin American electricity privatization has been primarily driven by a rapid increase in electricity demand, coupled with a shortage of domestic capital to meet future electric power generation investment needs. Privatization has involved both the sale of power operations to investors and agreements to allow incremental private investment in new electric facilities. Prominent among foreign investors are a number of U.S. electric utilities as well as some non-U.S. foreign utilities. Several petroleum companies have also entered the Latin American electricity market. Typically, privatization of utilities, and of electric utilities in particular, is accompanied by restructuring and changes in the regulatory regime. The absence of privatization does not always involve stringent regulatory activities by governments. Extensive privatization does not eliminate regulation. Recent privatization and restructuring activities created a variety of mixed models for the interaction of private interests, competition, and regulation. While research findings, such as Pollitt (1996), support the claim that privately owned utilities exhibit higher productive efficiency than SOEs, public

The Privatization Issue

11

debate is clouded by uncertainty concerning the resulting overall economic efficiency, as well as the extent to which other policy objectives are served well by privatization. Unfortunately, the variety of arguments supporting the various views is well supported by a plethora of scholarly evidence on all sides. Often, data, empirical methods, and results are subject to "questioning" motivation and are structured by a specific political philosophy. The energy crisis of the 1970s marks a watershed in the world's interest in the electric industry. Until the mid-1970s, electricity provision was a nonissue in public agenda the world over. Public concern, if any, was limited to ensuring that electrification will reach disadvantaged populations, mainly in rural areas. In the developed economies, the energy crisis focused attention on the efficiency with which electricity is produced and consumed. In the developing world, it awakened concern about the inadequacy of investments in the most basic elements of the existing infrastructure, generation first, and the so-called "wires-business" later. Following the energy crisis induced by the Organization of Oil Exporting Countries (OPEC) in 1973 and on, two fundamental forces joined to serve as catalysts that induced policymakers everywhere to consider private and restructured electricity provision as an alternative to the heretofore unified publicly and privately owned systems. In the Western economies, large, vertically integrated utilities, especially when owned by the public sector, were deemed inefficient. Energy shortages focused attention on conspicuous levels of consumption, on the need for conservation, on alternate and nonconventional sources of energy, and on the inadequacy of extant regulatory practices. Rateof-return regulation and historically determined, flat, embedded-costs rates were identified as the culprits. Many called for regulatory incentives to improve the situation.3 The U.S. Public Utilities Regulatory Policies Act (PURPA) of 1978 was the harbinger of change throughout the developed world. The implementation of the PURPA provisions was slow to come, and the implications were felt toward the end of the 1980s only. By the mid-1980s, public consensus was that rates rooted in marginal costs and incentives of various form were not sufficient as a mechanism to achieve efficiency in the electricity sector. The 1990s saw a variety of initiatives to improve efficiency by means of restructuring. In this, the world followed Great Britain and the United States. In many countries, the introduction of private capital and control, even in the case of minority stock ownership, was viewed with apprehension. In many ways, the regulation of a privately controlled monopoly was deemed easier than of a state-owned enterprise. The right of the public sector to exact particular behavior from a private utility was deemed justified, in light of the sweeping, or limited, protection from the competition that was being granted. Many claimed that the regulation of SOEs, by definition imbued with public interest, was redundant. Others point to the typical situation that clouds the expression of public interests in the operations of SOEs and introduces, through

12

Privatization and Restructuring of Electricity Provision

various political markets, narrow private interests. State-owned utilities are governed by politically appointed boards of directors, subject to ruling party interests and often to strong labor union influences. In countries governed by left-of-center governments, labor unions are often the holders of managerial decision-making powers, and boards of directors are relegated to a role of committees characterized by rubber-stamp, decision-making powers, in light of decisions made in labor union committee meetings. At the other extreme, the main fear that accompanies the introduction of private capital concerns the introduction of property rights that may stifle efforts to restructure the supply of electricity in the years following privatization. The need for restructuring may be motivated by a variety of arguments and induced by various catalysts. Concern for public interests may deem regulation of private utility inefficient, or structural changes may be necessitated by technological changes or shortages of particular fuels. The introduction of private interests introduces a clear definition of property rights that cannot be adversely affected thereafter. Owners of private capital in the utility become holders of veto powers in any effort to change the status quo. Restructuring becomes possible in a context of a general consensus only. Of course, it becomes much more difficult when there is a heterogeneity of private interests, which may result from the nature of the private owners and/or variety of utilities owned by a homogeneous group of private interests. It is for this reason that privatization efforts are intimately tied to restructuring efforts. THE MAIN ISSUES This book is not concerned with resolving technical controversies of measuring efficiency, equity, and other repercussions of privatization. The inclusion of private interests in the life of electric utilities is axiomatically assumed to be superior always to the exclusively politically motivated management. This book presents a mapping of arguments and experiences in a variety of political and technological contexts concerning electric SOEs divestitures. In itself, such mapping is interesting as a first step towards understanding a complex generic social phenomenon. It suggests the outer limits of economic reforms, as dictated by engineering, economic, and political constraints. Analysis of these limits enables rational public choices that accord well with social objectives. Can market forces alone steer modern electricity systems toward the twentyfirst century? What role is deemed appropriate for the public sector? What regulatory regimes are common, and which are appropriate under different market conditions? Can the electricity system be totally subdivided, so that generation, transmission, and distribution entities interact, guided by market price signals alone? Will there be sufficient investments in large base-load plants, and who will bear the cost of abandoned nuclear or outdated hydroelectric plants? Whose responsibility will it be to ensure sufficient capacity

13

The Privatization Issue

during periods of growth? Will competitive pressures provide sufficient incentives for technological progress? Will the price system ensure sustainable rates of energy utilization? Is a spot market for electricity a requisite component of an efficient system? Who will activate it, and how it will be operated? Who will ensure the provision of service to the poor and the distant? These and other issues are addressed in this book by reference to theoretically guided discussions and by exploring experiences with privatization and restructuring in various countries. Arguments and conditions in highly centralized, government-owned systems will be juxtaposed with decentralized and private systems. Thus, examples of private but centralized systems, such as the vertically integrated pre-PURPA U.S. utilities will be compared with the more decentralized post-PURPA U.S. systems. Pre-Thatcher England will be compared with the current conditions. Competition among local, government-owned producers in Norway will be compared to the highly centralized, governmentowned French and Israeli systems (see Table 1.3). It is to be expected that the changes that have been implemented heretofore have not come to a natural end. The process of reforms, even in the most advanced systems, is likely to continue and evolve. Sooner or later, the laggard, highly centralized, government-owned systems will begin to modernize. It is to be hoped that future changes will benefit from a considered look at what has been accomplished thus far. Not everything that has been done is without problems. Identification of snags and the resolution of controversies is likely to make future changes smoother and more cost effective. To sum up, the objectives of electricity privatization should be viewed in a wider context of electricity reforms whose purpose it is to enhance the "public good."

Table 1.3 Examples of Structures of Electric Systems

Ownership Government

Centralized

Decentralized

France Israel Pre-Thatcher England

Private

Pre-PURPA US

Post-PURPA US Post-Thatcher England

Mixed

Norway

14

Privatization and Restructuring of Electricity Provision

NOTES 1. Chapter 2 presents a nontechnical description of the rudimentary aspects of the electricity production technology and electricity terms. 2. Solomon Brothers, unpublished data, 1996. 3. For a summary of the issues, see Czamanski and Henderson 1981.

2 The Technology of Producing and Managing Electric Systems

Electricity is a catchall term that refers to a variety of phenomena, such as lightning and static electricity that occur naturally and generated electricity. In the electric industry, the term electricity is synonymous with electric current, which is the movement of electrons (the negatively charged parts of every atom) through power lines or other conducting material. Electric energy flows through power lines as a result of voltage1 created by electricity generating plants or generators. Electric energy, measured in kilowatt-hours (kwh), is delivered to points of consumption via a network of transmission and distribution (T&D) power lines. See Figure 2.1 for a graphic representation of an electric system. THE ELECTRICITY GENERATION BUSINESS Electricity is generated in bulk by power stations. The most common type of generators convert mechanical energy into electric energy. Typically, this is accomplished by spinning an electromagnet in which a moving magnetic field induces electric voltage and current into a conducting medium. Either a conductor can spin within a stationary magnetic field, or a magnetic field can spin within a stationary conductor. Mechanical generators produce voltage by creating a force on electrons in a conductor, by means of motion of a magnetic field and a conductor. This mo-

Figure 2.1 Schematic of a Simple Electric Power System

generator 3 voltage transformer generator 2

generator 1

voltage transformer voltage transformer

step-down substation primary distribution service

industrial customer

ransmission service

step-down substation secondary distribution service

secondary service transformer residential customer

Source: Adapted from M. Munasinghe, The Economics of Power System Reliability and Planning (Baltimore: Johns Hopkins University Press, 1979), 12.

Producing and Managing Electric Systems

17

tion is created by mechanical devices, such as turbines. As a result of this motion, electrons are continuously pumped into the conductor. Generating plants are classified also by the type of energy used at the station to convert energy into rotary movement, for example, coal, nuclear, hydroelectric, gas-oil, natural gas, and wind. The predominant type of power plant uses thermal energy to produce steam, which is then used to drive a steam turbine-generator. These fuels are alternate sources of thermal energy. Power stations are classified also by the net output that the station is capable of sustaining for an indefinite period without causing damage to the station. The declared net capacity of the station is expressed in megawatts (MW). To maintain the stability of the electric system, and since it is not practicable to store large quantities of electricity, generation of electricity must match the demand for electricity at all times. Consequently, the central coordination of the operation of all generating activities within each system is an important feature of each system. The demand for electricity is not constant over time. Fortunately, there exists a typical pattern of consumption, known as load curve. From the early morning hours, the demand for electricity increases steadily until the late afternoon hours and then decreases quite rapidly during the night. Of course, the pattern is different in different parts of the world and during the various seasons, depending on the need for heating, cooling, and lighting. Large generating plants use fuel most efficiently, especially when operating at or near their capacity. They are used first to meet demand. These socalled "base-load" units are operated continuously. Typically they have capacities from 800 to 1100 MW and use coal or nuclear fuels. The next group of plants are called intermediate load units. They are operated when total system demand exceeds the base load capacity. This happens for a fraction of the daily demand cycle. The intermediate units are smaller coal burning plants, ranging from 400 to 600 MW. For short periods of peak demand, peaking units are utilized, using a variety of fuels and ranging in size from 10 MW and up. A coal-fired generating plant consists of a boiler, fuel storage, and handling equipment, a steam turbine coupled with an electric generator, a condenser and pumps, fans and heaters, and air pollution control equipment. Oil and conventional natural gas plants have a similar design. To increase flexibility and to decrease reliance on a particular fuel in a number of places around the world, plants have been designed to burn either coal or fuel oil. The main difference between the various fossil fuel plants is in the design of the boiler, in the preparation of the fuel, and in the pollution control equipment. Most fossil fuel base-load plants have a thermal efficiency of between 35 and 41 percent. Of the total energy released by fuel combustion, most is dissipated into the atmosphere as part of the combustion process or is lost through radiation and convection to the surroundings. Nuclear power plants produce electricity in a way that is essentially similar to most fossil fuel plants. In a nuclear plant, thermal energy, or heat, is produced by a process called fission. The process consists of the splitting of atoms by

18

Privatization and Restructuring of Electricity

Provision

means of neutrons. When a nucleus of an atom is hit by an extra neutron, it splits and creates smaller atoms of other elements together with heat and more neutrons. These "new" neutrons hit more atoms of the original element thus creating fission chain. The vast amounts of thermal energy is used to produce steam that is used to propel turbines. The steam is then cooled, condensed into water, reused, cooled, and returned to its source. The typical nuclear fuel used in commercial reactors is made of uranium ore that has been processed and enriched. It is noteworthy that one pound of nuclear fuel is capable of producing more heat than 240 tons of coal, 830 barrels of oil, or 5 million cubic feet (Mmcf) of natural gas (Pacific Gas and Electric Company 1992). A major problem associated with the use of nuclear power plants involves the proper procedures for handling, treating, and disposing of nuclear waste. Several types of waste, classified in terms of the degree of their level of radioactivity, are created by nuclear plants. Dry, low-level radioactive waste is compacted, sealed into drums, and transported for burial in special waste sites. The main type of high-level radioactive waste that is produced by such plants consists of spent solid fuel. Often, this waste must be stored for a prolonged time on site before being transported to permanent disposal sites. While most base-load and intermediate plants are nuclear and coal fired, most peaking capacity are oil- or natural gas-fired internal combustion facilities. These engines are compact, can be started quickly, and are capable of reaching full load without delay. A gas turbine plant consists of a compressor, a combustor, a turbine-generator, and a starting motor. First, a hydrocarbon fuel is burned in a combustion chamber, into which fuel and air are admitted and ignited. Second, burned gas is fed into the turbine at high pressure. An open cycle plant takes air from the atmosphere. When the turbine's exhaust is connected to the compressor inlet, a much more efficient closed-cycle plant is obtained. In a combined-cycle plant, high temperature exhaust is channeled into a heat-recovery boiler to produce steam, which is used to power a steam turbine-generator. In many parts of the world, additional technologies are used to produce electricity. In places where water flows from higher to lower elevations, power is generated using gravitational energy. Water stored behind a dam is allowed to run downhill through a large pipe called a penstock and then spins blades of a turbine. The rotating blades rotate a turbine shaft, which in turn rotates a generator. In places with abundant water supply and naturally occurring elevation differences, hydroelectric power is the least costly way to generate electricity. In such cases, hydro plants can serve as base-load units. The first hydro plant in the United States was built in 1896 by the Central California Power Company. In other places, small hydro plants can serve as peaking units. During offpeak hours, water that has been used to drive a hydro plant during peak hours can be pumped to a higher elevation and used again during peak periods. The amount of energy generated by such pumped storage plants is only about 75

Producing and Managing Electric Systems

19

percent of the amount of energy needed to pump water into higher elevation storage. It is economical, however, because the energy used to pump the water is produced at a relatively low cost during off-peak periods. The first such plant was built in the United States in 1920 and had a capacity of 50 MW. By 1990, pumped storage capacity in the United States reached 12,500 MW. There exist other technologies for generating electricity, using a variety of energy sources. In some places, it is economical to utilize thermal energy from below the surface of the earth. Such energy is tapped by means of wells and conducted between a magnetically heated reservoir and a power-generating plant. Thus, for example, geysers are used in California to operate 1,291 MW of generating capacity. Sunlight can be used to create electron flow either in a photovoltaic cell or to heat a fluid that is used to operate an engine or turbine generator. Photovoltaic systems are modular and flexible. They can be used to meet a variety of load needs. Solar thermal systems concentrate heat into a "working fluid" that can drive a variety of engines. Each generating plant displays a different incremental heat rate, or the amount of thermal energy required to produce the next kilowatt-hour of electric energy for a given level of electric generation. Incremental heat rate is measured in British Thermal units per kilowatt-hour (Btu/kwh) or in equivalent barrels per megawatt-hour (eb/MWh). For each plant, the incremental heat rate rises as the level of output increases over the plant's relevant operating range. The curves that describe the changes in Btu/kwh as a function of MW vary according to plant design, operating conditions, and level of operating output. The use of the most economically cost-effective mix of resources to meet electric demand is termed economic dispatch. The cost of producing any given amount of electricity is lowest when all generating units operate at the same incremental cost, or system lambda, expressed in $/kwh. For example, a hypothetical system consists of two power plants: unit one uses oil while unit two burns natural gas (see Figure 2.2). Together, the two plants generate 290 MW at a system lambda of $0.05/kwh. As demand increases to 425 MW, examination of the incremental costs reveals that at the new output, these are equal when the incremental cost reaches $0,065, which then becomes the new system lambda. Among other factors, the system lambda is determined by past decisions concerning the additions to the system's generating plants. Prior to the time that expansion decisions are made, the system planners need to forecast future demand for electricity, both in terms of maximum demand and in terms of demand profiles over time. These daily and seasonal load curves serve to calculate an optimal expansion path of the system. The objective that drives the calculation is the minimization of total cost, including capacity and operating costs. Past implementation of optimal expansion decisions determine the particular plant configuration of a system and its system lambdas at a particular time. During the planning process, it is important to take into account unexpected changes in demand, such as instantaneous surges in demand that place

20

Privatization and Restructuring of Electricity Provision

Figure 2.2 Incremental Cost Curves for a Hypothetical System $/kWh

Demand (MW)

Power Generated unitl unit 2

Incremental cost ($/kWh)

L

290 425

100 155

190 270

$0,050 $0,065

$0,100

unit 1

unit 2

$0,065 $0,050

+55

100

+80

190

MW

an additional demand on the system. To meet this demand, the system's planners are required to provide spinning reserve, which is the margin of generating capacity available for immediate generation. THE WIRES-BUSINESS Electricity is transferred from power stations to final consumers through transmission and distribution systems. Transmission is the bulk transfer of electricity by means of a regional or national grid of 400 kv and/or 275 kv lines. The grid consists of overhead lines, underground cables, and substations. All large power stations are connected to the transmission grid. At various points the transmission grid is linked to regional distribution systems. Many, but not all, transmission systems are interconnected. There are a variety of links between the systems, and they differ in terms of their transfer capability. Distribution is the transfer of electricity from the grid supply points to final consumers. Distribution systems consist of a network of overhead lines, underground cables, and substations having successively lower voltages, ranging generally from 132 kv to 240v and below. It is important to distinguish

Producing and Managing Electric Systems

21

between distribution and supply activities. The latter is the bulk purchase of electricity at wholesale price and its sale to customers at retail price. The overhead network of wires is supported by steel towers and wood poles. The steel towers are used for lines operating at higher voltages. Increasingly, underground wires are used. Though the installation costs are higher, the underground wires are less costly to maintain. Also, they are less prone to damage by natural events. There are several indicators that characterize the size and performance of a distribution system. The size of a distribution system is measured by its simultaneous maximum demand (SMD), generally averaged over some short period of time, such as a half-hour. SMD is measured in MW. Distribution system availability is measured as the percentage of total number of minutes of supply lost within a year per customer. Unavailability of supply may be the result of both planned and unplanned events, including maintenance work. Line losses are unaccounted for electricity units that entered the system and cannot be delivered because of losses experienced naturally during the process of transformation and distribution. To respond effectively to such problems, power pools were formed. They were first organized in the United States during World War I, when demand for electricity rose sharply, and it was not possible to meet it immediately by building new capacity. Pools are contractual arrangements between two or more interconnected electric companies for the purpose of coordinating the operation of their generating and/or their transmission facilities. By combining the resources of the pool members, the pool can achieve improved system reliability and/or lower cost power. The commitments of pool members to the pool vary among the pools. The benefits to be achieved from pooling arrangements vary among the pools as well. The nature of the pool is determined by the needs of its members and by their ability to contribute to the pool's activities. Among the factors that determine a pool's character are the size of the interconnected systems, the mix of their generating plants, and the transmission capability of the members. A variety of benefits can be achieved by members of a power pool. Since electricity supply within an electric system flows to meet demand on call, a sudden surge in demand or a sudden failure of a generating unit can cause the entire system to shut down. Power pooling arrangement can improve the system's reliability by increasing the number of generating units available to meet power requirements of the entire pool. Thus, the impact of an imbalance between demand and supply in a pool is distributed over a larger number of generators and therefore is lessened. To meet unexpected surges in demand or failures of a generating unit or a major transmission line, utilities maintain a margin of generating capacity available to function immediately. This, called spinning reserve, is synchronized to the system. Other nonspinning reserve capacity requires generally twenty-four hours before starting operation, depending on the available tech-

22

Privatization and Restructuring of Electricity

Provision

nology. The amount of spinning reserve available within a system is calculated as spinning reserve = (capacity connected and ready / capacity in use) x 100 The size of the maintained spinning reserve margin is related to the level of demand and changes over time. During the peak hours of the day, the margin is small, while during the off-peak night hours, the margin grows substantially. Power pool members can lower the cost of maintaining spinning reserves by sharing it. Above all, members of a pool benefit from cost savings that result from power exchange agreements. This is especially effective in situations that member systems do not experience coinciding peak-demand periods. To supply its customers' high-cost peak demand, an electric company can obtain offpeak, low-cost generated electricity from another member. Indeed, a well-coordinated pool has a joint economic dispatching facility, so that demand within a pool is met by generating resources from anywhere in the pool, on the basis of system marginal cost only. At the end of each period, members share costs according to the use that the pool made of the member's capacity. The size of electric systems and the effectiveness of power pools is limited somewhat by power losses in the process of transmission and distribution. In an electric system, it is necessary to generate more electricity than is actually needed for all the previously mentioned needs. This is because each kw unit of load demanded gives rise to a small incremental loss of energy. Each component of the transmission and distribution system must have sufficient capacity to carry both demanded loads and their associated losses. Energy losses incurred in supplying the service increase inversely with voltage level. Line losses, or losses incurred in the transmission and distribution systems, can be classified as copper losses, core losses, and dielectric losses. Copper losses vary according to the square of the load current supplied and are present throughout the wires system, from the generator to the customer's meter. They result from power dissipated in the form of heat used to overcome the resistance of the transmission and distribution lines. Core, or iron, losses originate in inductive equipment, such as transformers. These losses are independent of load variations. They are in the form of heat dissipated in the iron core of a transformer, resulting from frictional resistance to the build up of the magnetic field in the core. Dielectric losses originate in the insulating material of cable wires and substation capacitors. They are similar in nature to core losses and result from resistance to the build-up of an electric field around a conductor. The amount of line losses depends on the geographic and other characteristics of a system. Wrhile typical systems in the United States experience losses that range from 4 to 6 percent, it is economical to wheel electricity over long distances, especially at higher voltages, when it is produced at a low cost by hydroelectric or nuclear technologies.

Producing and Managing Electric Systems

23

Finally, at the point of consumption, the quantity of electricity that leaves the system and is consumed is measured by a variety of meters. These instruments measure energy consumption in kilowatt-hours and demand in kilowatts. While it is possible to measure consumption continuously, because of cost considerations, it is generally limited to period measurements. Today, technology exists that makes it possible to measure consumption from distant locations and to control the amount of consumption by disconnecting the flow of electricity to consumers when predetermined conditions are reached. NOTE 1. According to Ohm's Law, one volt (V) is the electric force that produces a current of one ampere when applied steadily to a circuit with a resistance of one ohm. One thousand V is one kV.

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3 Political and Economic Constraints

There are very few who would deny the need to increase the allocative and productive efficiency of electricity supply as a means to promote the public good. Wherever public debate on issues of electricity reforms begins, politicians of all persuasions speak out loud in favor of privatization and other related reforms as a mechanism to improve conditions. In countries that have undergone reforms of ownership and/or structure already, the public debate focuses on fine-tuning the reforms. In countries that have yet to begin the process, public discourse is focused on the need, structure, and timing of actions to be taken. Indeed, privatization is deemed the most important and the most urgent step in the chain of necessary reforms. Aside from the lively, purely academic debates and the vague, but intense pronouncements of politicians, progress is paced and circumscribed by the art of the possible in a realm governed by a myriad of contradictory interests. Public-good objectives can be maximized only in a context of constraints imposed by interest groups. The expressed concern of most organized interest groups in preserving the extant suggests that they are well served by the current conditions. Some wish to improve their positions by reforms in directions that obviously further enhance personal positions. Public good can be served only by resolving conflicts and serving private interests. To understand the various arguments that populate the public discourse arena and the way that strategies are played out, it is imperative to meet the players and to understand

26

Privatization and Restructuring of Electricity

Provision

their interests, both proclaimed and real. It is important to understand the repercussions of the expected moves that might be made in response to reforms proposed and debated. Often the expected results are contrary to those desired, both from the private as well as the public interest. Even a broad brush caricature of the main actors yields a multiplicity of interests (see Figure 3.1). Within the locus of contracts that in general makes up the entity that constitutes the modern business firm,1 the interests of equity holders to maximize the net worth of their holdings does not accord with the interests of managers and workers (Jensen and Meckling 1976). The ability of owners to impose their will on managers and workers is circumscribed by the well-known asymmetric distribution of information and the presence of principal-agent relationships that characterizes the modern firm. In the case of all regulated utilities, the agency conditions are rather complicated by the presence of regulators who intervene on behalf of the public good. Often, managers are interested in perquisites, leisure, and easy life. The interest of workers goes much beyond salary levels and job security. Organized labor is often a major political actor that influences the definition of what constitutes the public good through electoral support of ''friendly" politicians. It turns out that regulation, be it the traditional rate-of-return regulation, the modern incentive regulation, or the variety of limit-setting regulations, influences the relative positions and strategies of the various players. Privatization introduces new motivations. These new forces are played out in view of distortions introduced by regulators. The interests of the various groups of consumers are not homogeneous as well. They compete for the lowest burden of the total electric bill as well as for the best quality of the services supplied. The interest of debt holders, while similar to that of equity owners, is more conservative and risk averse. Competitors, who typically provide alternate sources of electrons, are interested in maintaining, nay, increasing any subsidies to the wires business and by so doing in improving the price competitiveness of their products. The strategic interactions of the various interests create contingent equilibria, the nature of which depends on the relative strength of the various actors and on the regulatory and political framework within which the interaction takes place. Any attempt to move away from that which is considered "best under the circumstances" is likely to fail. Any attempt to change the rules that dictate the context of the interactions is deemed by all to be undesirable. The electricity sector tends to be deadlocked and riddled with conservatism. The power of those endowed with the public good, be they governments holding equity or regulators, is relatively unimpressive. MALADIES OF REGULATING A VERTICALLY INTEGRATED UTILITY To achieve allocative and technical efficiency in the absence of competition in the product market, the burden of disciplining the actors has been placed historically in the hands of regulators. From the inception of the first modern

Figure 3.1 The Central Actors in the Electricity Sector

Debt Holders 1 Equity holders

Managers

Regulators

Workers

Industrial Customers

Commercial Customers

Households

Competitors

28

Privatization and Restructuring of Electricity

Provision

public utilities commission over 120 years ago, the task of the regulators has been to protect the weak consumers facing the powerful monopolies. Price setting has been designed as the primary tool for this purpose. In competitive markets, competition among suppliers ensures that prices of products and services reflect the marginal costs of supplying them. It was the original purpose of regulatory activities to ensure that administratively imposed prices will simulate prices that would have occurred in a competitive environment, while ensuring simultaneously that electric companies receive revenues that generate a return on investment sufficient to ensure future supply of capital to the industry. Until quite recently, the role and practice of regulators was deemed to be part of a contract between society and the regulated utility.2 As society's agent, the utility was expected to provide its services to all who demanded it and at the least possible cost. The regulatory contract specified that in return for its services, the utility was allowed to earn, with minimum risk, a certain level of revenues that is consistent with earnings of other industries with similar risk factors. To ensure that the contract's terms are met, society through its representatives, the regulatory commission, "controls" the activity of the agent. There were two instruments that were typically used by the principal: (1) the principal engages in monitoring to ensure that the utility does not pass onto the principal costs that should have not been experienced in the process of producing the utility's services; and (2) the principal sets an upper limit on the profits that the utility could earn. At the backdrop of the regulatory contract was the presumption that the utilities are distinct from unregulated companies in the absence of product market competition only. Prior to the 1970s, in the academic as well as in the professional literature, profit motive was ascribed to all companies, including regulated utilities. In addition to product market competition or the presence of regulation, three other forces were presumed to discipline utility decision makers sufficiently and to prevent them from deviating from profit maximization. One is the prominent presence of a market for corporate control. The frequency with which the managements of industrial concerns are replaced by outside managers suggests that wherever nonprofit-maximizing behavior by managers leads to deviation of the book value of corporate assets from their market value, the deviations are a sufficient condition to invite takeover bids. A somewhat different and yet related disciplining force arises out of the market for managerial labor. Managerial mobility is circumscribed by the fact that a manager who has permitted several successful takeover bids in his professional lifetime will experience a decrease in the present value of his human capital. It is presumed that self-interested managers are interested in maximizing the return to their human capital and thus will be adverse to takeovers. Still another disciplining force is associated with a market for financial capital. The basic cost of capital is determined through the interaction of the demand for and the supply of investable funds. The cost of capital to a specific firm, however, is also a function of the past and current profit performance of

Political and Economic

Constraints

29

the firm. Inasmuch as management perquisites are bought out of profits, ability to raise capital in the capital markets is also in the interest of management and serves as another disciplining force. In this conceptual context, regulatory practice, known as rate-of-return regulation, evolved and flourished until the late 1970s. In the basic model, the regulated firm's goal is to maximize profits, which is defined as the difference between revenues, labor costs, and capital costs. Revenues and costs experienced by the utility are a function of the relevant market-determined prices and the utility-determined quantities. The firm is presumed to maximize profits by selecting inputs of production subject to the maximum allowable rate of return on investments, as determined by regulators. The regulatory constraint precludes the firm from earning maximal profits. As a compensating result, the firm will employ an exaggerated quantity of capital. (See Appendix for detailed description of this A-J model and other related models.) This A-J model is a useful paradigm for examining the repercussion of behavior on the part of utilities and regulators that deviates from "proper" behavior (i.e., set the allowed rate-of-return equal to the market-determined, required return on investment). The A-J effect implies that capital waste comes about only if the allowed rate-of-return exceeds the cost of capital. Overcapitalization occurs when the regulator is guilty of misidentifying the true cost of capital. The A-J thesis allows the firm to operate off the production frontier, since earnings above the cost of capital that lead to higher costs are rewarded via higher rates. Inefficient operation will continue as long as the utility is allowed to earn more than its cost of capital. Until the mid-1970s, Morton (1971) and many others contended that regulators sometimes seek to encourage efficiency by allowing the utility to earn a rate-of-return that exceeds its cost of capital, as long as the utility achieves this rate through efficient operation. However, a regulatory commission dedicated to efficiency and eliminating misallocations of resources will take away the excess earnings even if the utility earned a return above cost of capital due to its superior efficiency. Can the utility, let alone the commission, identify the opportunity cost of capital so that the allowed rate-of-return will be equal to it over time? At best, this is a difficult task. Efficient management will attempt to identify the leastcost combination of resources. Such an effort requires information on current and projected changes in factor prices, on the elasticity of demand, on scale of output, on changing technology, on relative prices, and on other economic factors. Thus, the least-cost combination of factors is at best an estimate that will change continuously as existing plants, processes, and relative prices change. Proponents of regulatory disciplining prowess suggest that changing economic circumstances are capable of penalizing utilities for inefficient decisions and thus, supplement regulators' toolbox. At the same time, the existence of a tight ceiling on profits may create a disincentive for efficient operation. The managers may become less cost con-

30

Privatization and Restructuring of Electricity Provision

scious. Because of the moral hazard problem, it is not desirable to strip the utility of all incentives to reduce costs and to improve service, even if it were possible to limit the utility's earnings to a fixed amount. It may cause the utility to become reckless in its efforts to control expenses. In the profit-maximization framework, the existence of redundant expenses is a result of regulation. But, the situation may be in fact worse still in that the utility may not be a profit maximizer. Indeed, it may prefer expenditures on staff and/or advertising that increase sales. In expense-preference models, such as that of Crew and Kleindorfer (1979), the firm maximizes a utility function that includes profits and other elements that represent benefits to managers. The expensepreference model yields a result that is consistent with the profit-maximizing model in that the regulated firm is not cost minimizing. The firm employs too much capital and too little labor. The overcapitalization persists for the expensepreference. For the expense-preference firm, the A-J effect is zero when regulators reduce the allowed rate-of-return to the level of the cost of capital. Changing the constraint has the effect of changing the effect profit has on the value of the objective function. Regulation has the effect of substituting inefficiency in the use of staff for the A-J type of inefficiency in the use of capital. SEPARATION OF OWNERSHIP FROM MANAGEMENT The first electric companies started operating in major urban centers. Indeed, the very first street lighting operation took place in the United Kingdom in 1881, and in lower Manhattan, when on 4 September 1882, Thomas Edison connected and lighted an area of Spruce, Wall, Nassau, and Pearl streets, including the offices of J. P. Morgan and the New York Tribune (Baldwin 1995). Rural areas were generally not supplied with electric service. It is thus that the early electric utilities were not interconnected. In a quest to exploit economies of scale, small companies grew horizontally and vertically. Wider geographic regions were served by utilities that provided generating, transmission, and distribution services.3 Many companies expanded even further by controlling the supply of fuels for their generating plants. In the absence of stringent regulation, some companies were permitted to own and control competing fuels, such as natural gas supply and heating oil. Even these early corporations were subject to workers' and managers' taste for nonproductive activities, such as perquisites and/or leisure, at the expense of the firm's profits. Such maladies of the modern firm, caused by an organizational structure in which ownership and management are in separate hands, were studied extensively first by Jensen and Meckling (1976). Any perfect monitoring of perquisites and associated enforcement mechanisms, such as Fama's (1980) perfect labor market for managers, would make regulatory monitoring unnecessary and zero profits optimal. Until quite recently, however, wage contracts in regulated industries did not typically provide penalties for imprudent behavior. Furthermore, since the profit motive that drives stock-

Political and Economic

Constraints

31

holders to reward or to punish new managers for past behavior is diluted by the regulation itself, managerial mobility among regulated firms would not appear to provide the same disciplinary force as is suggested by Fama's competitive example. Thus, it is necessary to assume that other forces that may discipline managers are imperfect. The regulator has two instruments with which to influence the manager's behavior—the allowed rate-of-return and monitoring wasteful behavior. In the absence of product market competition, utility managers' taste for nonpecuniary benefits is assumed here to have no productive component whatsoever. The manager's "quiet life" is an often quoted illustration that captures the essence of nonproductive expenses. The stockholders have no way of converting managerial waste into profits. The Jensen-Meckling capital market disciplines the manager by forcing down the stock price of new shares offered, as the owner reduces his share of the firm. No similar mechanism exists as the regulator reduces the allowed rateof-return. In the limit, for example, if stockholders could extract profits at management's expense, these would be subjected to the regulation and eliminated. Hence, stockholders have no incentive to discipline managers in response to regulatory action. The capital market, however, can protect itself against a reduction in management's ownership share in the same fashion as Jensen and Meckling discussed for the unregulated firm. The only difference for the regulated case is that the market must anticipate that output is likely to fall as management's ownership share is reduced, whereas it remains constant in the absence of regulation. OPTIMAL REGULATION AND INCENTIVES In the absence of monitoring, the regulator is incapable of preventing inefficiency. Inefficiency takes on the form of either monopoly profits or of nonpecuniary waste. In principal, monitoring offers some hope. If, in addition to detecting more total slack, monitoring also raises the fraction of waste that is discovered, the manager is encouraged to substitute output for waste. Waste, however, is discouraged by the substitution effect only, since tightening the feasible region, whether by monitoring or by reducing the allowed return, normally has the unfavorable effect of more waste. In practice, the regulator cannot observe the manager perfectly and consequently the results are between what can be termed perverse regulation and perfect regulation. The regulator's problem is to find the best mix of instruments, given that he has limited powers of observation. It is in this sense of a search by the regulators for the best combination of the two tools that stand at their disposal, that the 1980s regulatory practices have evolved as regulatory incentives. Besides monitoring and variation in the allowed rate-of-return, many other regulatory practices were tried in the early 1980s to induce specific behavior patterns by the regulated utilities. The vari-

32

Privatization and Restructuring of Electricity

Provision

ety of practices can be grouped according to the source of information flows that constitute the basis for regulatory actions, and according to the reward structure that is adopted as an incentive for the desired behavior. As is suggested by Table 3.1, four main types of incentives were tried. A and C are mechanism that use information that is obtained from the regulated agent directly. Mechanisms B and D use additional information obtained from other sources. A and B are incentive mechanism that reward the regulated agent based on the productivity of the agent alone. Mechanism C and D include additional measures of performance. An example of a type A mechanism called the Incentive Rate-of-Return Mechanism (IROR) was devised the Federal Energy Regulatory Commission (FERC) for use on the Alaska Natural Gas Transportation System construction project and to be adopted by various state regulators of electricity (see Illinois Commerce Commission 1980). According to this mechanism, the company is allowed to realize a rate-of-return on common equity based upon a cost performance ratio (CPR) calculated as CPR = actual construction cost / estimated construction cost As the CPR rises, regulators decrease the allowed rate-of-return on equity. The CPR measures the success of management in controlling costs. Increases in costs due to economic factors outside the control of management are not included in the CPR. On the other hand, cost increases due to project delays, for example, are attributed to management errors. In this mechanism, the burden of revealing accurate information rests on the regulated agent. The allowed rate-of-return is clearly a function of the agent's assessment of expected costs. The agent's rewards are determined by prior information possessed by the agent in the form of his beliefs regarding project costs. In the absence of other information flows, there is a clear and unambiguous incentive for the agent to inflate initial estimates of costs. Such inflated estimates bias the CPR downward, resulting in a higher allowed rate-of-return on equity than would be possible if the agent revealed the "truth." This is a typical result of informational asymmetry that plagues regulatory principal-agent situations. Regulators presume that while the IROR is a problematic incentive mechanism, it creates an alliance with capital markets. Since large construction projects are perceived to have high risk, suppliers of capital require higher interest on debt capital. The existence of an IROR mechanism is presumed to provide at least some incentive to utility managers to keep cost overruns under control. A similar mechanism has been adopted by most regulators in the context of collecting revenues through fuel adjustment clauses, a mechanism that is still common in many countries. By imposing a time lag in the collection of revenues, an incentive is created to improve asset and cash flow management. In the absence oflagged revenue collection, fuel adjustment clauses have the character of pricing on the basis of cost plus, without any incentive to control costs.

33

Political and Economic Constraints

Table 3.1 Classification of Incentive Mechanisms Reward structure

Source of information:

Source of information:

agent alone

agent and others

Agent's productivity alone

A

B

Total system productivity

C

D

Note: There are undoubtedly many ways to classify incentive mechanisms. The one suggested here is somewhat arbitrary and suggestive at best.

An insurance policy with a deductible clause is a risk-sharing contract and constitutes an example of type B incentive mechanism. In general, this type of contract stipulates that the insured party is responsible for paying damages below some stipulated amount. The insurance company will pay for damages only when they exceed the cutoff point. The general structure of such cost sharing is p f = p n + 7 (ca - ce) where Pf is the final payment, Pn is the negotiated payment, y is the costsharing rate, ca are the actual costs, and ce are the estimated costs. The net payment realized by the agent is determined by two components: (1) the payment established ex ante as being a fair and reasonable return on assets, and (2) an adjustment based on the deviation of actual costs from estimated costs. The cost-sharing rate takes a value from 0 to 1, inclusive, and is determined by both parties to the contract prior to its implementation. Thus, 7 reflects the risk that each party will bear during the enforcement of the contract. Type C incentive mechanisms were studied extensively in the literature ever since the early 1970s (Ross 1973; Leland and Pyle 1977). They are similar to the mechanisms of type A and B, yet they differ in the sense that the basis of the reward structure is total performance of the entity under the manager's supervision. According to the Ross-type mechanism, for example, the utility manager is paid a current wage that is proportional to the current value of the company adjusted for the relevant risk factor in the electric industry. At some later time, the manager receives additional "compensation" that depends on the terminal value of the firm. Should the resulting value be greater than that promised to the firm's debt holders, the manager will receive some fraction of

34

Privatization and Restructuring of Electricity Provision

the final value. Similarly, should the firm experience losses or go bankrupt, the manager will be assessed a penalty at a level that represents some agreedupon fraction of the losses. A number of type D incentive mechanisms have become common in electricity regulation. An early and much mimicked mechanism of this sort was the New Mexico cost-of-service-indexing method (COSI). This mechanism allows a rate increase to occur if the utility company earns less than a minimum allowed rate-of-return during a quarter, or triggers a rate decrease if the rate-of-return on common equity rises a maximum allowed rate-of-return. The same adjustment on a per kwh basis is also applied to the energy charge for each class of service. Kaufman and Profozich (1979) studied the impact of COSI on service rates. While it was found that COSI-managed electric utilities led to significantly lower electricity bills, all other things being equal, it is difficult to determine its impact on regulatory efficiency. The regulated utilities indicated that COSI freed management from the burden of the rate case cycle. On the other hand, the commission estimated that unification of the COSI data requires two to four times the effort required for a similar function in a traditional rate case. THE COMPETITIVE PRESSURES MEDICINE Recognition that regulation induces inefficiency began to be an accepted notion in the United States already during the late 1970s. Perhaps the main motivation behind PURPA was an effort to increase efficiency, even though it was spawned by OPEC-manipulated energy shortages. Earnest efforts to decrease inefficiency through incentive mechanisms were made during the 1980s. A variety of mechanisms were considered, tried, and abandoned. The effort to introduce independent power producers (IPPs) through PURPA may be viewed as a recognition that incentives alone will not do the job. It is important to note that the choice of tools to achieve increased efficiency was influenced critically by the initial conditions in the United States. It is quite surprising, especially to outside observers, that in the United States where private, vertically integrated, state-regulated utilities are in fact largely interconnected, product market competition was not considered as an efficient policy tool and did not evolve naturally. Power pools and regional reliability councils were structured as cartel-type instruments, instead of as means to improve efficiency. IPPs were introduced to promote alternate energy sources. IPPs and neighboring utilities could have been a source of product market competition. Competition as a disciplining force was considered in the United States in the 1990s only, following the major changes that were already introduced in Europe. Outside the United States, principally in Great Britain, restructuring and privatization were deemed as the preferred, if not the only, means to achieve the same ends. Of course, the initial conditions in Great Britain were quite

Political and Economic

Constraints

35

different. Until 1990, 94 percent of electricity generated in England and Wales was produced by the nationalized Central Electricity Generating Board (CEGB). The CEGB owned and operated the transmission system and operated the interconnection with France and Scotland. Twelve state controlled Area Boards purchased electricity (mostly from the CEGB), distributed it, and sold it to customers within their designated areas in England and Wales. To ensure the availability of sufficient capacity, the CEGB planned for a margin of generating capacity. This, together with its operation of power stations and its control of the transmission system, gave the CEGB an effective monopoly. In February 1988, HM Government published a White Paper entitled "Privatizing Electricity." The White Paper included proposals for the introduction of competition into generation and supply. The subsequent Electricity Act was enacted in July 1989, and the new industry structure was introduced on 31 March 1990. In other countries, competition is being introduced without privatization. In Norway, it is motivated by local concerns for efficiency. Throughout continental Europe, and in France in particular, it is being imposed from without by European Union agreements. In interconnected systems, be they national or international, the availability of electrons supplied reliably and at a lower unit cost together with a mandate to sell the cheapest electrons available, provide a strong survival incentive to produce efficiently locally. The electricity world is becoming increasingly interconnected.4 The United States and Canada, as well as Europe, are expected to be free of transmission bottlenecks. Plans are being prepared today so that in the future, Europe will be connected with Africa and Asia by means of the Mediterranean circumferential transmission highway. In spite of this progress, at least three major issues remain as stumbling blocks on the road to product market competition. In the vast majority of countries with integrated and government-owned systems, concern for national security and self-reliance in the form of assured supply is the main obstacle to institutional innovation. The profit motive and market institutions are viewed as sufficient mechanisms for the supply of bread and milk, but lacking as far as the electricity infrastructure is concerned. The risk is considered to be just too great.5 Who would forecast demand? Who would ensure that capacity additions will be planned and supplied? Who would have an interest to coordinate the system to the benefit of all? In most countries, restructuring decisions are held in balance by practical, sometimes interests-oriented, and not by philosophical considerations. Two central issues that concern all proponents of reforms are proper transmissionpricing mechanisms and full accounting for "stranded costs." Transmission pricing is an issue akin to highway pricing. Because electrons that are pushed into an electric system are indistinguishable from each other and thus are not traceable, it is not possible to identify their source at the point of consumption and thus to estimate accurately the marginal cost of delivering them to the customer through the transmission and distribution sys-

36

Privatization and Restructuring of Electricity Provision

terns. Since it is possible to meter the outgoing quantities of electrons at the various points of generation, and similarly the incoming quantities of electrons at the various points of consumption, it is possible to estimate the corresponding average cost of moving electrons throughout the interconnected wires network. The assignment of responsibility for inducing these costs on an average basis introduces a distortion and an inefficiency that was supposed to be eliminated by product competition. It is possible to show that a transmission price can be determined in a manner that is compatible with economic efficiency and clearly neutral in its effects upon all competitors in electricity generation. A correctly constructed regime of transmission pricing may in fact achieve the efficiency and equity goals that justify competition. An even steeper obstacle to restructuring is posed by existing property rights. Past investments in generating plants were carried out under specific conditions of an agreed upon social contract between utilities and regulators. Past investments were approved by regulators, and indeed, utilities have been collecting returns on past investments through approved rates. No doubt has been expressed that restructuring will make some of the past investments redundant. New generating companies will begin to operate only if their products can be produced at a lower cost. In other words, it is the purpose of product market competition, or at least an expected result, that at least some of the existing plants will not be able to compete successfully and therefore will become useless. Restructuring causes potential damages to existing equity holders of generating plants, be they private individuals, as in the case of privately owned utilities, or be they voters, as in the case of government-owned companies. Since the resulting stranded costs6 are substantial it is not concievable, according to some, that equity holders will be made to absorb them, without some sharing of the burden with the other players in the restructuring drama. There are many options. Some of these are (1) to write off these capital costs, that is, to make shareholders take the loss; (2) to minimize the loss by improving the efficiency of utilities as business entities, thereby reducing their overall operating costs; (3) to redistribute these costs onto captive customers (i.e., residential and small commercial customers) who will not be able to buy power from competitive suppliers until many years after large customers can do so; (4) to distribute costs over all customers, through exit fees, transmission, distribution surcharges, or other mechanisms; (5) to distribute costs over all customers by delaying the transition to retail competition, to allow more time for capital recovery; or (6) to redistribute some of these costs onto the public sector through the nationalization of particularly uneconomic assets. These and very many other issues, local to specific conditions within a particular electric system, mar the debate concerning the desirability of introducing additional and powerful motives into the intertwined weave of the electric world. The following chapters describe the debates and actions that are being taken w;ith increasing frequency throughout the world. The results are not en-

Political and Economic

37

Constraints

tirely convincing one way or another. Changing the status quo is intended to remove inefficiency-promoting incentives, but often they introduce new distorting mechanisms. In the final analysis, judgment should be based on the bottom-line results. Can we allocate the responsibility for the changed results unequivocally to privatization, or is it at least partly due to restructuring? NOTES 1. Very often electricity is supplied by cooperatives and other not-for-profit business units. In such cases, equity holders are replaced by customers-owners. To the extent that a significant portion of the electricity output is sold outside the service area of the utility, the customers-owners behave in a manner similar to equity owners. 2. Much of this chapter is from Czamanski and Henderson 1981. 3. It is most interesting that Thomas Edison almost from the outset (12 December 1913) viewed the electricity business as the wires business of transmission, distribution, and regulation, and not the production of electrons. "Electricity is not power; electricity is a method of transporting power," in Baldwin 1995, 138. 4. It is important to stress that the electricity transmission network, like a highway, is subject to bottlenecks, and that its capacity to transmit electrons from areas of excess supply to areas of excess demand is capacity constrained. 5. Such doubts were raised frequently by legislators in Israel's Parliament during debates concerning restructuring and privatization. One could almost discern modern, capitalistic echoes of Lenin's statement that "communism would result from Soviet power plus electrification of the country" (The Economist, 14 June 1997, 73). 6. According to a simple definition, stranded costs are costs that electric utilities are currently permitted to recover through their rates, but whose recovery may be impeded or prevented by the advent of competition in the industry.

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4 Electric Thatcherism in the United Kingdom

Events in the United Kingdom during the early 1990s provided an inspiration for proponents of privatization and restructuring of the electric industry throughout the world. Through vigorous steps, the United Kingdom implemented, within a very short period of time, a revolution. A nationalized and integrated electricity system was transformed into a decentralized, private, and competitive industry. Efficiency gains were achieved. Proponents claim that the adjustment costs were at best small and insignificant. The experience in the United Kingdom serves as a backdrop to all discussions of reforms. The extent of benefits and costs that were experienced and the applicability of the experience to countries with different initial conditions is debated repeatedly everywhere. ELECTRICITY SUPPLY IN THE PRE-THATCHER PERIOD Though the first practical applications of electricity in the United Kingdom were in the mid-nineteenth century, the first public supply of electricity took place in 1881 for the purpose of street lighting. Over the next forty years, a variety of suppliers began generating and distributing electricity for private customers, at various voltages and frequencies. By 1921, some 480 such suppliers were operating in England and Wales. The Electricity (Supply) Act of 1926 was intended to promote the exploitation of economies of scale through, among others, the introduction of unifor-

40

Privatization and Restructuring of Electricity Provision

mity of practice, concentration of generating sites and a national transmission system. To this end, a central authority was created, and by the mid-1930s, a national 132 kV grid was completed. Through the Electricity Acts of 1947 and 1957, the multitude of diverse private operators in England and Wales were brought under state control. Some 560 separate organizations were integrated into twelve regional Area Boards. The 1957 Act created the CEGB and the Electricity Council. The appointment of members to the various bodies was carried out by the government. From a diverse industry that was born in 1881, by 1957 the United Kingdom created a nationalized electricity supply industry. By 1990, the CEGB generated some 94 percent of the total supply requirements of England and Wales. It owned and operated the transmission system as well as the interconnections with the neighboring French and Scottish systems. It was responsible for ensuring that sufficient capacity was available. The twelve Area Boards purchased electricity almost exclusively from the CEGB, and distributed and sold it to customers within designated areas. The Electricity Council exercised a coordinating function (see Figure 4.1). Since the 1950s the consumption of primary energy in the United Kingdom grew in tandem with the growth of the gross domestic product (GDP), albeit at a somewhat slower rate. The annual consumption of electricity in the United Kingdom grew from 99 TWh1 in 1960 to 261 TWh in 1989 on the eve of restructuring, or from 7 percent of the final energy consumption to 15 percent (see Table 4.1). Of course, as elsewhere, the growth has not been uniform over time. Between 1960 and the first energy crisis in 1973, electricity consumption grew at an average annual rate of more than 6 percent. After a recovery during the late 1970s, the second energy crisis in 1979 brought about another recessionary period and a decline in electricity consumption. From 1982 until the restructuring, consumption grew at average annual rate of 3 percent. It is noteworthy that during the period from 1960 to 1989, the share of electricity in the energy consumption by the industrial sector grew from 7 percent to 18 percent, while the share of domestic consumption grew from 8 percent to 20 percent. Many claim that a prolonged period of stable growth in the electric system is a prerequisite condition for restructuring initiatives. During periods of rapid growth, awakened interests of investors may create greed to privatize among some politicians. Growing firms are a natural target for takeovers. At the same time, such periods raise fears of declining quality of service among other politicians. Opponents of reforms are quick to point out the dangers of insufficient investments in capacity that may follow privatization. Stability is a welcome backdrop for reforms. THE RESTRUCTURING INITIATIVE OF 1989 The initial conditions on the eve of restructuring reforms are critically responsible for the nature and timing of the reforms. Thus, it is important to point out that the U.K. electric system was never fully vertically integrated.

Electric Thatcherism in the United Kingdom

41

Figure 4.1 The Electricity System in the United Kingdom before 1989 CEGB Generation Transmission

Area Board 12

Area Board 1

Area Board 2

Area Board 3

Customers in Area 1 Customers in Area 2 Customers in Area 3 Customers in Area 12

The area boards were independent organizations that served as intervening filters between the CEGB and the consumers. The situation in the United Kingdom, even in the pre-Thatcher days, was quite unlike many countries that had, and still have, nationalized and/or integrated systems. In the United States, for example, privately owned electric utilities were permitted to own the entire system, including the generating plants, the transmission, and the distribution network. The prereforms customer in the United States dealt with an integrated utility. Similarly, in countries like Israel, the individual consumer faces a government-owned utility that happens to be the largest corporation in the country. This semidecentralized industrial structure continued to exist in the United Kingdom until the end of the 1980s. In 1988, the Conservative government of Mrs. Thatcher presented a bill to the British Parliament as part of its effort to privatize the electricity supply industry.2 The purpose of the proposed actions was to introduce new disciplining forces into what was considered by international standards an inefficient

42

Privatization and Restructuring of Electricity Provision

Table 4.1 U.K. Final Energy Consumption 1960 Twh

1960 %

1970 Twh

1970 %

1980 Twh

1980 %

1989 Twh

1989 %

Electricity

99

7

192

11

224

14

261

15

Petroleum

376

25

802

47

726

44

739

43

93

6

181

11

493

30

547

32

912

62

523

31

213

13

184

11

1,480

100

1,698

100

1,657

100

1,731

100

Energy source

Gas Solid Fuels Total

Source: Kleinwort Benson Limited, ' T h e Regional Electricity Companies Share Offers," 1990, 19.

industry. The interaction among three new interests was to provide appropriate incentives and efficiency gains. According to the vision behind the bill, private interests will be disciplined primarily by product market competition. To this end, new, market-type institutions were proposed to insure the existence of vigorous competition. Back-up protection of consumer interests was to be provided by a vigorous, albeit small, regulatory body called OFFER. Thus, restructuring and new style regulation was part of the British effort to privatize electricity supply. The centerpiece of the proposed restructuring effort was the break-up of the electricity supply. The original unification of the multitude of generators was justified by arguments of natural monopoly and the need to exploit extant economies of scale. With time, the continued expansion in generating capacity, technological innovation in traditional methods of producing electricity, and the introduction of new technologies, such as natural gas-fueled, combinedcycle plants led to the conclusion that the natural monopoly status of the electricity generation industry is no longer justified. The new PowerGen (PG) company was to handle some 30 percent of the existing capacity, to the exclusion of nuclear plants. The rest of the existing capacity, including nuclear plants, was to be transferred to National Power (NP). Soon afterward, in the absence of private interest in nuclear power, a third entity, Nuclear Electric (NE), was set up as a separate company. Concomitantly to the proposed restructuring of the generation business that was in the hands of the CEGB, the business of the twelve Area Boards was to be transferred to twelve Regional Electricity Companies (RECs), without changes in the definition of their geographic area of responsibility. In addition, the national grid and the CEGB's interests in the interconnections with France and Scotland, as well as pumped-storage power stations, was to be transferred to a National Grid Company (NGC). The NGC was to be owned through a holding company by the twelve RECs (see Figure 4.2).

Electric Thatcherism in the United Kingdom

43

Figure 4.2 The Electricity Industry in the United Kingdom after 1990

Figure 4.2 does not indicate with sufficient clarity the extent of the reform. In addition to the three generating companies, electricity can be sold into the electricity pool by SP and SHE, the two Scottish companies; by EDF, the French company through the existing interconnection; and by new independent generators. Under the reform, the physical flows of electricity are not changed, inasmuch as the generated electricity flows through the national transmission system and across the wires of the local distribution systems. However, the National Grid Company and the twelve regional companies are under an obligation to provide to all equal terms for the use of their systems. In effect, the wires business has become a common carrier of product that is not always owned by the carrier (see Figure 4.3). The various lines indicate some of the contractual relationships possible. Generators sell into the pool, and the distribution companies buy from the pool. However, bilateral contracts are possible between generators and distribution companies and between generators and large customers. In addition, any large customer can buy from any licensed supplier, including any generator and any distribution company, and not necessarily from the local distribution company. This freedom to contract for electricity is to be extended to all customers by 1998. From the inception of the reform, the definition of large customers changed gradually, from some 5,000 customers with maximum demand of 1

44

Privatization and Restructuring of Electricity Provision

Figure 4.3 Electricity Flows in the United Kingdom after 1990

MW, to some 50,000 customers with maximum demand of 100 kw in year two of the reform, and so on. The ability of customers to shop around for the best deal, termed supply competition, is a unique feature of the reform in the United Kingdom.3 Supply competition constitutes a major supplement to the competition in generation. Together, they make for vigorous product market competition and the major source of discipline in the industry. THE U.K. POWER POOL—THE ELECTRICITY MARKETPLACE Power pools in the United States are voluntary arrangements between two or more interconnected electric companies for the purpose of coordinating the operation of their generating and/or transmitting facilities.4 In the United Kingdom, the pool was established on 31 March 1990 as the new market for trading in electricity among generators and suppliers. Membership in the pool is mandatory for all licensed generators and suppliers. Indeed, all generators who sell in excess of 10 MW of electrical power from a single generating station and suppliers who supply more than 500 kw must be pool members. Others who may not fall under the above criteria but who wish to be connected to the national grid also need to be pool members. In general, pool

Electric Thatcherism in the United Kingdom

45

members are obliged to sell all their output and to purchase electricity from other pool members under the trading arrangements of the pool. The pool itself does not buy or sell electricity. The trading takes place under a set of rules, including the calculation of the financial obligations among the traders, following an execution of transactions. The pool constitutes the market for electricity. Its arrangements determine the price of electricity in response to changes in the demand for and supply of electricity. The price changes every half-hour. Two types of prices are determined: the price at which electricity is supplied to the pool, or pool input price (pip), and the price at which electricity is purchased from the pool, or pool output price (pop). Generators receive a payment that is based on these two prices. The pip is set for each half-hour of the trading day by reference to the forecasted demand and reserve requirements and the resulting notional generation schedule that constitutes the basis for calculating the system marginal price (SMP). On the day prior to the activity, participating generators submit to the pool a list of generating facilities that are available for central dispatching by the pool. The list includes a price offer and the availability characteristics of the proposed facilities. By combining the information from all available generators and the system-wide demand for the upcoming day, the grid operator prepares the unconstrained schedule of half-hour by half-hour activities. After adjustments for changes of availability that may result from the published unconstrained schedule, a new revised unconstrained schedule is prepared. Pip is comprised of two elements. The first element is the SMP, which is constructed from the unconstrained schedule. A variety of factors are taken into account in constructing the SMP from the offer prices provided by the generators. Among these are the overall system load curve and the characteristics of the offers, including the capacities of the various available facilities, the nature of the availability (on line or reserve), generating technology and time needed to bring the facilities on line and the cost of sudden increased and reduced rates of operation. Pip is augmented by a second element, known as the capacity element. It reflects the loss of load probability (LOLP), or the probability that supply will be lost because the available generation will be insufficient to meet all forthcoming demand. The pool rules define the maximum value of the lost load (VLL) as £2 per kwh linked to the Retail Price Index of 1990-1991. The pip is then defined as pip = SMP + LOLP (VLL - SMP) The actual payment to generators, however, is determined ex post only, following the particular day's operations. It is only then that it becomes apparent what demand and production conditions prevailed during the day and the actual production costs that were incurred. While a notional dispatching schedule was prepared before the start of the day's operations, the grid operator

46

Privatization and Restructuring of Electricity Provision

dispatches centrally for the entire pool with the intent to maintain a short-term balance of generation and demand, honor each generators dispatching preferences, and account for breakdowns and transmission bottlenecks. The actual payment at the end of the day takes into account pip, adjusted for changes in availability. Capacity that is made available by a generator in excess of the revised unconstrained schedule is rewarded at the capacity element of pip, adjusted so that SMP is replaced in the formula by bid price, which is the average price at which the entire scheduled set of generating facilities would have been made available by the generator. When the output of a generator is reduced because of transmission or other external problems, the generator is paid a reduced amount that reflects the reduced output and the offer price. Other adjustments are made according to preset rules of the pool. Suppliers of electricity pay the pool output price, pop, on the basis of their metered demand adjusted for line-losses during transmission. The adjustment ensures that each half-hour demand equals exactly the metered generation. Pop is essentially pip, adjusted for ancillary services and actual operations. In this fashion, the daily money flows through the pool are in balance at all times. Pool prices vary according to demand and supply conditions over the hours of each day. While the general pattern is quite stable, actual prices are not easily predictable because of variations in plant availability and changing operating conditions. A certain degree of hedging against such fluctuations is possible through bilateral contracts that pool members can enter with others. The purpose of hedging is to increase the probability that all costs, including fuel costs, that generators incur are recovered. It introduces a greater degree of stability in the terms of supply contracts with customers. These so-called contracts for differences are mechanisms for reallocating part of the existing financial risk without trading in electricity. It is typical that a generator contracts to pay periodic payment to a supplier in return for a fee that the generator will receive for the difference between the pip and an agreedupon price, known as the strike price. The contract is for a specified quantity of electricity and time period. The size of the fee depends on the size of the difference and the perception of the risk by both parties. THE NATIONAL GRID COMPANY The National Grid Company (NGC) owns and operates a grid that consists of some 13,500 circuit kilometers of overhead lines supported by more than 21,000 pylons. In addition, it has some 700 kilometers of underground cables, 7,000 kilometers of high voltage transmission lines, and over 280 substations containing switch gear and transformers. It is controlled through a number of regional centers and one national control center. In addition, the NGC provides various ancillary services that are necessary to maintain the transmission system. The ''plant" of the NGC was fashioned from the original 132 kV national transmission system that was completed by 1938. An additional 275 V net-

47

Electric Thatcherism in the United Kingdom

work was superimposed on the original network in the 1950s. During the 1960s, parts of the 275 V network were further upgraded to 400 kV. In the mid-1970s, parts of the original 132 kV network was no longer needed for transmission, and so were transferred to the Area Boards for use of the distribution network. It is noteworthy that future developments of the transmission network, as in the case of the distribution network, place a burden on the NGC to secure property rights to land, and usage rights from the appropriate land-use planning authorities. In some countries, land is relatively scarce, especially in the urban areas, and it is argued that a government-owned entity may have easier access to land than a private company. Table 4.2 presents some rudimentary data on the transmission system prior to restructuring. Even prior to privatization, the system was extremely reliable. With the exception of 1987,5 the ratio of delivered energy to the sum of delivered and estimated undelivered energy stood consistently at 99.999 percent. This is despite the fact that parts of the transmission system has been at or near the limits of their licensed capacity. There was no apparent reason to privatize the grid, which under the restructured system continued to serve as the public utility infrastructure. Nevertheless, it was decided to sell the grid's property rights and obligations to the RECs. Each REC was allocated a share in the NG, the holding company of the grid, proportional to the R E C s net assets. NG ownership structure is as follows: Eastern Electricity

12.5 percent

East Midlands Electricity London Electricity Manweb

8.4 10.5 5.5

Midlands Electricity Northern Electric NORWEB SEEBOARD Southern Electric South Wales Electricity SWEB Yorkshire Electricity

9.2 6.5 8.2 7.3 11.0 5.4 6.3 9.2

As the gird and pool operator, the new company was licensed to engage in several businesses. In addition to transmission, NGC was awarded licenses to settle accounts, to manage interconnections, to perform certain ancillary services, and to generate limited amounts of electricity for its own use of balancing demand and supply. At the same time, it was explicitly prohibited to trade in electricity. Indeed, in order to promote competition, the NGC was mandated to prevent cross-subsidies among its various businesses. To this end, the NGC keeps separate audited accounts pertaining to each business.

48

Privatization and Restructuring of Electricity Provision

Table 4.2 Transmission System Performance Prior to Restructuring

Maximum System Demand Met (MW)

Total Electricity Requirements (GWh)

System Maximum Average Cold Day Demand (MW)

1985- 1986

45,185

231,984

45.0

1986- 1987

47,925

237,913

46.7

1987- 1988

46,935

244,659

47.4

1988- 1989

46,875

248,322

47.7

1989- 1990

46,763

253,952

Year

Source: Kleinwort Benson Limited, "The Regional Electricity Companies Share Offers," 1990, 86,91.

COMPETITION IN GENERATION AND IN SUPPLY On the eve of the reforms in the United Kingdom, there were in fact three separate systems: England and Wales, Scotland, and Northern Ireland. In terms of peak demand in the period of 1995 to 1996, England and Wales account for some 49,000 MW, Scotland for some 6,000 MW, and Northern Ireland for some 1,500 MW. Wholesale supply of electricity in England and Wales was dominated by the three major generating companies that were set up as the main successors to the CEGB: National Power, PowerGen, and Nuclear Electric (see Table 4.3). Since privatization almost fifty new generating licenses have been issued in England and Wales. The multiplicity of players has led to increasingly competitive market, even for base load generation. In the meantime, combined-cycle, gas-fueled turbines have become a competitive method of generating electricity. There are several reasons for this. First, they are less expensive than coal-fired plants. Second, their modular design and short construction time makes this technology flexible. They are suitable for turnkey financing contracts, placing a greater risk on plant suppliers. In addition, they reduce environmental costs.6 By 1996,9,500 MW of these plants were commissioned and another 15,000 MW were in various stages of planning and construction. This so-called "dash for gas" represents a major challenge to the existing generating capacity. Since the demand for electricity in England and Wales is expected to grow at no more than 1 percent per year until the year 2000, new generators are expected to reach up to 20 percent market share. The market penetration of new players may leave stranded existing, "old technology" generating capacity. In the spirit of promoting fair competition among all players, special arrangements were made for nuclear power plant decommissioning and renewable fuel sources generation. It was recognized at the time of privatization that these technologies will have a hard time compet-

49

Electric Thatcherism in the United Kingdom Table 4.3 Electricity Generation in England and Wales, 1996 Net Capacity (MW)

Share (%)

National Power

19,269

30

PowerGen

15,282

24

Nuclear Electric

7,128

11

Magnox Electric

2,989

4

First Hydro

2,088

3

Independents

5,924

9

Source: Kleinwort Benson Limited, "The Regional Electricity Companies Share Offers," 1990, 19.

ing with other technologies. By order of the Secretary of State, the twelve RECs were obliged to buy specified amounts of electricity generated by nuclear power plants in England and Wales until 1998. In Scotland, until privatization, the competitiveness of nuclear generation was enhanced by a premium payment from fossil fuel generator to the nuclear plant. The competitiveness of renewable fuels plants was bolstered by a fossil fuel levy, which stood at 0.7 percent as of 1 April 1997. The Non Fossil Fuel Obligation (NFFO) pertains to landfill gas, hydro, wind, municipal and industrial waste, energy crops, combined heat and power schemes, and agricultural and forestry waste. At the retail level, prior to restructuring, consumers of electricity received their supply from the area boards. In 1990, there were some 22.5 million customers of electricity. A little more than one-third of these were industrial customers, about one-third were domestic, and just under one-third were commercial and others (see Table 4.4). In the United Kingdom, as elsewhere, industrial customers use electricity for melting, heating and drying, for space heating and lighting, and for powering machinery. For some purposes, notably space and process heating, electricity stands in competition with other energy forms. In some sectors, such as electromechanical processing, electricity has no competitors. In general, sales to industry are affected by the level and nature of industrial activity and by the relative price of electricity. In the domestic and the commercial sectors, electricity is used for central and space heating, air conditioning, water heating, for powering kitchen and other appliances, and for lighting. In both sectors, electricity competes with other fuels for space and water heating. In addition to price, the use of electricity is influenced by demographic changes, by the market penetration of electrical appliances, design of offices and retail establishments, and by automation. Consumers of electricity are physically connected to their local RECs. Indeed, they have no choice about it. Some customers today and all customers

50

Privatization and Restructuring of Electricity Provision Table 4.4 U.K. Electricity Consumers by Type, 1990

Customers (000s)

Sales (TWh)

Sales (%)

Industrial

188

87

36.9

Domestic

20,305

80

33.7

1,702

61

25.8

Other

226

9

3.6

Total

22 422

236

100.0

Commercial

Source: Kleinwort Benson Limited, k The Regional Electricity Companies Share Offers;' 1990, 30.

by 1998 will be able to purchase electricity from suppliers elsewhere under second-tier licenses. With the exception of customers who generate their own electricity and those few who are permitted a direct connection to the national grid, second-tier electricity is supplied through the local R E C s distribution infrastructure. Thus, the vast majority of electrical transactions are carried out with at least some involvement of the RECs. The RECs' business includes: distribution of electricity, supply of electricity (including the purchase and sale of electricity), sale of electrical appliances, electrical contracting, and some generation. It is noteworthy that the RECs are traders in electricity as well as common carriers for other peoples' electricity. They cannot discriminate between their own supply business and that of others. They cannot charge differential rates, except when the differences are cost justified. Distribution is the principal business of the RECs. Electricity is supplied to the RECs from the national grid at transformation stations, or supply points, where it is transformed from 400kv, or 275kv, to 132 kv. Electricity flows into the RECs' network from power stations located in their geographical areas and from neighboring RECs. Most customers receive electricity after a series of transformations at 240 v. The distribution business of the RECs is regulated and their revenues are controlled through a price-cap formula. The maximum revenues that a REC can receive from its distribution business is determined by a maximum average distribution charge per unit multiplied by the number of units distributed. The formula that controls the price is composed of two elements: the retail price index (RPI) and an amount that reflects differences among the RECs in the cost of providing the RECs distribution services (X ). These costs vary according to variations in the voltage at which consumers receive electricity and the time of consumption. There are four main categories of distribution services:

Electric Thatcherism in the United Kingdom

51

LVl: electricity distributed at 1 kV to domestic and small nondomestic consumers outside night time periods. LV2: electricity distributed at under 1 kV to domestic and small nondomestic consumers during night time periods. LV3: all other electricity distributed at below 1. HV: all other electricity distributed, other than the electricity distributed at extra high voltage. Thus, for any fiscal year, the allowed maximum average price per unit of electricity distributed by the REC is the previous year's price with the current year's weights. The result is then increased by the RPI + X p corrected for line losses in the distribution network. The starting values were determined for each REC in the context of its operating license. Two types of corrections govern the actual charges for the distribution service. Each year's charges are based on projections of the expected volume of electricity to be delivered in each category, line-losses, and RPI. Overcharging and undercharging may result from wrong forecasts. The deviations in charges and resulting income of the REC is corrected for in the following year, including interest charges in favor of either customers or the REC. Two aspects of the resulting pricing scheme are noteworthy. A natural result of the usage categories is the existence of peak-load, or time-of-use, pricing for the distribution business. This result is similar to what a competitive market would have created. Second, not all the services of the RECs are subject to regulatory supervision. Distribution to extra, high-voltage customers are not included in the price control formula. Connection services, repositioning of mains, services provided on the customer's premises, and meters are not price regulated. In addition to their distribution business, RECs are traders in electricity. This is their supply business. The RECs are obliged and licensed to sell electricity on demand within the geographic area defined as their distribution monopoly. The obligation is not symmetric. Consumers of electricity within the distribution area of a particular REC are free to choose their electricity supplier. They may elect to satisfy some or all of their electricity needs by purchases from their local REC or from any second-tier supplier. Thus, while in some parts of the world fairness of competition is raised as an issue whenever a common carrier is allowed to act as a trader, the U.K. reforms ignored such concerns. To prevent possible conflict of interest issues the U.K. law introduced defence mechanisms in the form of strict license oversight and price regulation of both the distribution and the supply business. Clearly, the price control of the distribution business is far more important as a mechanism that ensures that all electricity, be it supplied by the local REC or be it supplied by others, is charged the same distribution price. At the same time, the regulation prevents cross-subsidies in favor of the RECs electricity. Also, it prevents cross-subsidies within the supply business among dif-

52

Privatization and Restructuring of Electricity Provision

ferent groups of customers, say those with maximum demand of above and below 1 MW. Of course, the presence of vigorous competition among suppliers should limit the need for price regulation. In this sense, the regulated price constitutes an upper limit, or price-cap, on the actual price. The maximum average price per kwh of electricity that a REC can charge its customers, including those residing outside its monopoly area and supplied under a second-tier license, is determined by a formula, Y + RPI - Xs where Y includes all the costs that the REC incurs in the process of obtaining and supplying electricity and that it cannot control. These costs may or may not be regulated, and they include, for example, the cost of electricity purchased from the pool under the pool output price and the transmission charges levied by the NGC. Certain costs incurred by suppliers are dependent on the nature of the supply business, such as the number of customers and not the volume of consumption. The RPI - X s is intended to cover these additional costs as well as the supplier's profits. As in the case of price regulation of the distribution business, a base amount, determined at the time that the license was awarded, is increased each fiscal year by the amount of the retail price index minus a correction. In the initial year, Xs was set at zero. Each year the weights used in the formula are changed to reflect changes in the composition of quantity of electricity supplied in the different categories. These changes are forecast by the supplier, together with forecasts of the RPI. Wrong forecasts, in favor of the REC or in favor of consumers, are corrected in the following year, including interest charges. The major objection to the introduction of competition in the supply business stemmed from those skeptics who considered the potential benefits from alternate supply sources to be lower than the search costs that they might entail. While the extent of the initial competition in supply was limited to large customers only, as many as one-third of all such customers, accounting for some 50 percent of the possible supply in the competitive market, chose to go the competitive route. More interesting, some 1,000 customers elected from the start to take electricity under contracts related to fluctuating pool prices, rather than under a fixed price.7 Wholesale and retail competition in England and Wales is fueled by the powerful economic interests that were created by restructuring and privatization. The players-owned pool, the marketplace for electricity, ensures price fluctuations that reflect demand and supply imbalances. In the wholesale market, the weaker players are protected, at least for a limited time, by purchase obligations and by fossil-fuel tax. In the retail market, institutions were fashioned to enable access of second-tier suppliers to the consumer. Strict regulation of distribution pricing enabled retail consumers to shop and to realize

Electric Thatcherism in the United Kingdom

53

savings. Another component that ensures equal access at the wholesale and at the retail level is the unbundled transmission system, operated by the NGC. In all, a combination of property rights, imposed rules by which competition is played out, and price controls ensures that the desired improvements in efficiency are in fact achieved. THE SYSTEMS IN SCOTLAND AND IN NORTHERN IRELAND The initial conditions in Scotland and in Northern Ireland were quite distinct from those in England and Wales prior to restructuring. Both systems are quite small. While Scotland was interconnected to a limited extend, Northern Ireland was an electric "island," for all intents and purposes. In Scotland, supply was dominated by two vertically integrated utilities, North of Scotland HydroElectric Board and South of Scotland Electricity Board. Some 50 percent of the electricity requirements in Scotland are supplied by nuclear power plants. Prior to privatization in 1992 and 1993, all electricity in Northern Ireland was supplied by a single vertically integrated utility, Northern Ireland Electricity (NIE). It owned and operated four power stations with a capacity of 2,300 MW and with peak demand of 1,515 MW. Small system size, load curves influenced by the relatively homogeneous nature of the customer base, limited interconnections with other systems, and the presence of nuclear and hydroelectric capacity made the reforms in Scotland and Northern Ireland an interesting experiment and a model for reforms in other small systems around the world. Prior to privatization, the generating assets of the two boards in Scotland were transferred to three companies: Hydro-Electric, Scottish Power, and Scottish Nuclear (see Table 4.5). The first two were to be privatized, while Scottish Nuclear was to remain in the government's hands. To minimize risk, and in order to place a diversified mix of generating capacity at the disposal of each company, a number of contractual arrangements were put in place prior to privatization. For example, Hydro-Electric provides 200 MW of hydro capacity to Scottish Power and Scottish Power provides 600 MW of coal-fired capacity to Hydro-Electric, all under contract and without a change in property rights. It is important to note that both privatized companies remained vertically integrated, engaging in generation, transmission, distribution, and supply of electricity. In Northern Ireland, the four power plants were privatized. The largest plant was purchased in 1992 by British Gas, and it operated as a subsidiary, Premier Power. Two plants were purchased by a consortium and are operated under the name Nigen. The fourth plant was privatized by a management buyout. Finally, NIE was successfully floated on the U.K. stock exchange. It remained a transmission and distribution company without any significant generating capacity. While the system is unbundled, NIE does engage in the supply business, fashioned on the model of the English and Welsh distribution companies.

54

Privatization and Restructuring of Electricity Provision

Table 4.5 Net Capacity and Output of Hydro-Electric and Scottish Power, 1990 to 1991 Hydro-Electric MW

Hydro-Electric GWh

Scottish Power MW

Scottish Power GWh

-

-

3,888

12,719

Dual oil and gas

1,284

3,870

-

-

Conventional hydro

1,064

3,133

125

303

Pumped storage

300

179

399

261

Other

178

279

55

Total

2,826

7,461

4,467

Coal

13,293

Source: Barclays de Zoete Wedd Limited and The British Linen Bank Limited, "The Two Scottish Electricity Companies Share Offers," 1991, 19.

There are no power pools in Scotland and in Northern Ireland. Indeed, there is no mandated wholesale competition in either market. To improve matters somewhat, efforts are being made to improve the interconnections among the systems of Scotland, Northern Ireland, England, and Wales. The interconnection between Scotland and England and Wales is being upgraded to 2,200 MW capacity. Scottish Power is improving its link with NIE, and by the year 2000, the total export capacity of the Scottish companies will expand by some 1,600 MW. The interconnections will improve the participation of the Scottish companies as second-tier suppliers in England and Wales (see Table 4.6). In both systems, as in England and Wales, provisions have been made to introduce nonconventional energy sources. It is generally agreed that power pools and wholesale competition will be introduced in both systems over time. Third party access to the systems and second-tier licenses by companies from England and Wales have resulted in retail competition in both systems. In Northern Ireland, supply competition encompasses the entire range of customers, and NIE does not hold monopoly powers over the supply business. The Scottish companies, on the other hand, continue to repel competition by aggressive pricing. In all, it is evident that it is possible to introduce elements of competition even in the face of vertically integrated utilities. Stringent regulation that ensures, among other things, third-party access to transmission and distribution tend to press downward on prices. Obviously, price competition in the face of private interests to generate profits leads to cost savings. It is the role of the regulator to ensure that these savings are shared and do not result in reduced service quality.

55

Electric Thatcherism in the United Kingdom Table 4.6 Net Capacity and Share of the United Kingdom, January 1996 Net Capacity (MW)

Share of U.K. (Percentage)

Scottish Power

4,203

6.0

Hydro-Electric

3,701

5.0

Scottish Nuclear

2,420

4.0

980

1.5

Premier Power NIGEN

808

1.0

Coolkeeragh Power

333

<1.0

11,815

17.0

TOTAL

Source: Barclays de Zoete Wedd Limited and The British Linen Bank Limited, "The Two Scottish Electricity Companies Share Offers," 1991, 19.

REGULATION AND PERFORMANCE OF THE PRIVATIZED SYSTEM Under provisions of the 1989 Electricity Act, the regulatory authority in the United Kingdom is vested in the Secretary of State and in the Director General of Electricity Supply (DGES), who is appointed by the Secretary of State. The general charge of the regulators is • to secure that all reasonable demands for electricity are satisfied. • to secure that all holders of licenses are able to finance the activities authorized by their licenses. • to promote competition in generation (wholesale competition) and in supply of electricity (retail competition). In addition, the regulators are mandated to • protect electricity consumers from supply license holders with respect to charges, terms of supply, and quality of service. • promote efficiency on the part of transmission and supply licensees. • promote research and development by licensees. • promote the health and safety of the public and of workers engaged in the generation, transmission, and supply of electricity. With the exception of the mandate to promote competition, the above charges to regulators in the United Kingdom do not differ in any significant way from

56

Privatization and Restructuring of Electricity Provision

those to regulators in other countries, operating under different industry structures. The same charges could be fashioned for a regulator facing a single, vertically integrated, privately owned utility. The distinctive character of the U.K. regulatory regime becomes apparent from an examination of the specific regulatory actions and regulatory culture that were instituted at the time of the restructuring and that have continually evolved ever since. The regulatory practice in the United Kingdom was set in motion by the policy statement sent by the first DGES to the Secretary of State on 17 October 1990. It makes clear that license conditions, especially second-tier licenses, and contractual arrangements are the principal mechanisms for framing private interests that interact through the marketplace. The extant competition in the wholesale and retail markets should be a sufficient disciplining mechanism to protect all interests. Price-cap regulation is an important, albeit secondary, safeguard for franchise customers. The DGES's charge to promote competition in the United Kingdom must be viewed in light of three related practices that predated the Electricity Act. The Fair Trading Act of 1973 set provisions for the control of private monopolies in general. The Electricity Act extended the provisions of the Fair Trading Act to the electricity industry. In general, restrictive business practices are dealt with in the United Kingdom by the Director General of Fair Trading. Normal directives, augmented by the Competition Act of 1980, serve as guidelines for evaluating the repercussions of mergers in the electricity industry. Given that the DGES was granted by the Electricity Act the responsibility for enforcing compliance under the conditions of licenses, the DGES and the Director General of Fair Trading have developed consultations procedures to evaluate mergers, before these are evaluated by the Monopolies and Mergers Commission. In addition, the electricity industry in the United Kingdom is subject to competition rules that govern industry within the European Community. Several articles of the Treaty of Rome are noteworthy. Article 85(1) explicitly prohibits all actions that may affect trade in a way that has the effect of "prevention, restriction or distortion of competition within the common market." Article 86 prohibits the formation of an entity that will have a dominant position in the marketplace and so affect trade among member states. Article 92(1) seeks to prevent unfair competition by prohibiting the granting of subsidies by member states. As a result the various institutions created by the Electricity Act, specifically pooling and settlements arrangements, codes governing the operations of the grid and distribution networks, coal purchase contracts and obligations toward nuclear power were all submitted for review by the commission's Director-General for Competition, from whom it received a favorable review. The Electricity Act provisions for competitive pressures, together with the fair trading provisions within the United Kingdom and within the European Community, would suggest that the watchdog role of the regulator is of secondary importance. And indeed, in comparison to other countries, the office

Electric Thatcherism in the United Kingdom

57

of electricity regulation that constitutes the staff of the DGES is rather small. And yet, the DGES has created extensive rules and regulations that govern its own actions. The DGES decides what and when to investigate. The regulator has the power to request and to obtain all information at will and the decision process does not involve a quasi-judiciary procedure as in the United States. The regulator, at least in the first instance, has limited power to resist or oppose regulatory actions. Albeit, these can be challenged in the courts. The powers assumed by the DGES to monitor and to make final judgments is very surprising. The United Kingdom has put in place market forces (the "suspenders") and regulatory mechanisms (the "belt") to promote and to induce significant improvements in the performance of the electric systems in the United Kingdom. Were the desired improvements achieved? The answer is a resounding "yes" and a somewhat meeker "no." The choice of a benchmark for comparison determines the answer one chooses to give. In relation to the situation prior to the 1990s, the evaluation is positive. In relation to expected improvements, the answer is negative. In terms of electricity prices, the United Kingdom has experienced continuous improvements over the last few years. Just from 1996 to 1997, the typical domestic electricity bill dropped by £8 in cash terms, from £274 in 1996, vat not included. The typical bill in 1990 stood at £317, vat not included. The £33 drop over the six-year period represents an 11 percent improvement in real terms, after correcting for inflation. The improvement was much better for industrial customers. Though prices increased immediately after privatization, for typical industrial customers (see Table 4.7) from 1993-1994, and until 1996-1997, average prices for the three types of customers dropped by 14 percent in cash terms and by 21 percent after correcting for inflation (see Table 4.8). In international terms, the U.K. industrial tariffs have become quite competitive (see Table 4.9). But of course, electricity prices are influenced not only by the wholesale and retail competition that the restructuring made possible. They include also regulated transmission and distribution rates that account for some 25 percent of the typical household electricity bill. Thus, for example, in 1994 the DGES announced a reduction in distribution charges that ranged from 11 to 17 percent and an additional reduction of between 10 to 13 percent in 1996. These reductions were instituted as a result of changes in methods of valuing the RECs assets and not as a result of changing the RPI - Xs formula. In some sense, this was a typical response of the DGES to the wide-scale criticism that the nationalized assets were sold off to investors at a particularly low price, yielding windfall profits to investors at the expense of taxpayers. The real issue behind these regulatory actions of the DGES is should the regulator control prices or profits. The regulatory philosophy behind the RPI - Xs formula is that it provides incentives to improve efficiency, which are then shared among consumers and shareholders. This is assured by the review process every five years. Indeed, after the first five years, the RECs operations have yielded

58

Privatization and Restructuring of Electricity Provision

Table 4.7 Hypothetical Industrial Customers Type

Maximum Demand

A

Maximum Consumption (MWh/year)

Annual Load Factor* (%)

kW

1,752

40

2.5 MW

8,760

40

52,560

60

500

B C

10

MW

*Load factor is defined as the ratio of the average load to a maximum load during a period. Table 4.8 Typical Prices for Hypothetical Industrial Customers, Selected Years Type

1989-90

1993-94

A

4.67

B C RPI

1/1/95

4/1/95

1/1/96

4/1/96

Real Change from 1989 - 90 to 1996 - 97

5.67

5.22

5.18

5.09

4.86

-20.4%

4.52

n/a

4.56

4.51

4.53

4.38

-25.9

3.92

n/a

4.00

4.03

4.03

3.90

-23.9

117.40

141.50

146.00

149.00

150.20

152.60

60.0

Source: www.ElectricityAssociation.org.lJK, 20 May 1997.

significant profits. It was the position of the DGES that reducing these profits in the nextfive-yearperiod may reduce the RECs incentives to struggle for efficiency gains and, above all, it would constitute a breach of faith with investors. The true extent of the issue has become apparent during the last few years. This was a period characterized by extensive changes in ownership of property rights throughout the U.K. electricity industry. Until 31 March 1995, the President of the Board of Trade held on behalf of the government a "golden share" in the RECs. It prevented the concentration of ownership in any REC by limiting ownership of shares by any one entity to 15 percent. With the expiration of the government's "golden share," the United Kingdom entered an era of takeovers and of mergers. The initial activity from 1995 to 1996 is described in Table 4.10. To prevent adverse effects of mergers on competition, already in April 1996 the government blocked bids by National Power and by PowerGen for Southern Electric and for Midlands Electric. The increasing concentration of market power raises the fear that under a variety of assumptions concerning demand elasticity, companies will raise prices sub-

59

Electric Thatcherism in the United Kingdom

Table 4.9 Typical Prices for Hypothetical Industrial Customers, Selected Countries, 1996 Country

A

B

C

Germany

8.47

7.91

6.37

Italy

7.47

6.89

4.59

Austria

7.3

7.23

6.04

Belgium

6.87

6.46

4.73

Spain

6.59

6.08

5.30

Luxembourg

6.59

5.43

4.40

Portugal

6.50

6.40

5.30

Ireland

5.46

5.06

4.13

Netherlands

5.42

5.26

4.42

France

5.25

5.21

4.10

U.K.

5.09

4.53

4.03

Greece

4.86

4.86

3.59

Denmark

4.60

4.48

4.11

Finland

4.36

4.29

Sweden

3.96

3.12

2.56

Source: www.Electricity Association.org.UK, 20 September 1996.

stantially above marginal costs and create profits at the expense of consumers. Such possibility increases with the reduction in the number of players. A concentrated industry provides better opportunities for collusive actions that increase the profits of all players. Such profits may create a problem for the DGES. It is unlikely that the regulator will be capable of discovering everything, nor that it would be in the public interest to limit profits beyond a certain limit. It is not clear what the limits are that should be placed on market power. The problem stems from the special nature of the electricity industry that makes

60

Privatization and Restructuring of Electricity Provision

Table 4.10 Takeover Bids for RECs; Status as of December 1996 Company

Bidder

The Bid (bn£)

Outcome

Eastern Electricity

Hanson

2.50

Completed 9/18/95

East Midlands Electricity

Dominion Resources (US)

1.27

Agreed 12/18/96

London Electricity

Entergy (US)

1.07

Completed 10/12/95

Midlands Electricity

Avon Energy Partners (US)

1.73

Completed 6/6/96

Northern Electric

CalEnergy (US)

NORWEB

.78

Completed 12/24/96

North West Water

1.79

Completed 11/9/95

SEEBOARD

Central and Southwest (US)

1.60

Completed 1/11/96

SWALEC

Welsh Water

.88

Completed 1/29/96

SWEB

Southern Group (US)

1.10

Completed 9/18/95

the measurement of market power particularly difficult. For example, the Herfindahl-Hirschmann index (Tirole 1988) measures concentration using the sum of squares of market shares for the firms in that market. This, of course, requires a definition of a market. In an interconnected system, the geographic scope of a market depends crucially on the transmission system performance and the operation of the power pool. In places that the transmission links are not fully loaded, electricity can flow relatively freely between geographic areas, thus increasing the size of the relevant market. Should the Scottish system be considered as part of market power examination in England and Wales? As markets increase in size, so shrink indexes of concentration. At the same time, a very large market may experience bottlenecks in transmission and in distribution making a priori calculations of market power quite different form ex post calculations. Furthermore, load profiles and technological topology of an electric system may make a particular company an indispensable entity in the system, giving it market power much beyond its size. The proper measurement of market power requires the performance of operational simulations under a variety of market conditions as a prerequisite to calculating concentration indexes. While in general capacity provides the basis for measuring concentration, its use in the electricity industry may be misleading. This is because the elec-

Electric Thatcherism in the United Kingdom

61

trie capacity is not homogeneous. The importance of particular elements within a system depends on the marginal cost of putting it into action at a particular time. Blind application of concentration indexes based on capacity would overestimate the power of high marginal-cost capacity and underestimate the equivalent power of low marginal-cost capacity. This characteristic also leads to the conclusion that simulation is the proper method for measuring market power. It is claimed occasionally that the market power of National Power and PowerGen together are an effective duopoly leading to electricity prices substantially above marginal costs. Thus, while electricity bills in the United Kingdom are shrinking as a result of restructuring, it may be the case that they are not shrinking as far as they possibly could. Finally, it is noteworthy that electricity in the United Kingdom is highly reliable. Availability stands at 99.98 percent. About 90 percent of interrupted service is restored within three hours from notification. Out of 24 million domestic customers in 1995 and 1996, only 674 were disconnected from service. During the same year, DGES reported that complaints from customers fell by 22 percent, standing at about 50 percent of the complaints in 1991 and 1992. It is difficult to examine the British experience heretofore by taking apart the observed results in terms of the variety of possible influences as suggested in the previous chapter. The short experience notwithstanding, it is almost impossible to separate the influence of profit motivation from the cajoling and constraining effects of the particular brand of incentive regulation that has been adopted. It is remarkable to observe the frequency with which the rules of the game are being adjusted and fine-tuned. Obviously, the system is not in an equilibrium, and much time will pass before the behavior of the various actors will be stable and amenable to a coherent examination. It is clear, however, that each change in the rules of the game leads to changes in the patterns of behaviour and in the efficiency results—just as it is predicted by the simple model of the previous chapter. NOTES 1. TWh, or terawatt-hour, is 1,000,000,000 kilowatt-hours. 2. Mrs. Thatcher's government presented its proposals in a White Paper entitled ''Privatizing Electricity" in 1988. The Electricity Act received Royal Assent in July 1989, and the new industry structure was introduced on 31 March 1990. 3. Norway, New Zealand, Chile, and Argentina have introduced a similar, though partial, supply competition. 4. See Chapter 2 for a detailed description of pooling. 5. This variation was due to storms in October 1987. 6. In comparison to coal-fired plants, combined-cycle gas plants consume 27 percent less fuel, and emit 58 percent less carbon dioxide and 80 percent less nitrogen oxide for each kwh. 7. S. C. Littlechild, 29 April 1993, lecture before the Royal Academy of Engineering.

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5 Israel

The United Kingdom and Israel provide an excellent backdrop against which to compare and contrast restructuring efforts. Israel's electricity system was fashioned by the British, who ruled much of the Middle East for almost onethird of the twentieth century; in Israel from 1918, when General Allenby marched into the then Turkish Palestine, and until the declaration of independence by Israel in the late 1940s. As in the United Kingdom prior to the 1990s, Israel's electricity is a government-owned system. In contrast to the United Kingdom's determined restructuring and privatization, Israel is an excellent example of missed opportunity and policy making by procrastination. MONOPOLY RIGHTS BY CONCESSION The sole electric utility in Israel was incorporated on 29 March 1923 as the Palestine Electric Corporation Ltd. The name of the company was later changed to the Israel Electric Corporation (IEC) so as to reflect the nature of its owners. The State of Israel owns 99.8 percent of the company stock. The rest of the stock is owned by a variety of unknown private owners. There is no market for the company's securities. The IEC is a classic example of an SOE. On 5 March 1926, the company was granted two concessions by the British High Commissioner for Palestine, the representative of the British govern-

64

Privatization and Restructuring of Electricity Provision

ment in the region. By means of a "Concession Ordinance," the company was granted the Jordan Concession and the Yarkon Concession to generate, supply, and distribute electricity exclusively throughout Israel, with the exception of Jerusalem. The concessions were granted for a period of seventy years, until 5 March 1996. By the terms of the concessions, the duration could be extended by the government, should the IEC request it. It is important to note that the Concession Ordinance specified the actions that would be required at the time of expiration of the concession or in the event that the assets of the company would be nationalized. In both cases, the state of Israel will be obligated to assume the rights and the obligations of the IEC and to satisfy all outstanding debts and obligations. In addition, the state of Israel is required to pay an unspecified compensation to the IEC for all undepreciated assets of the company. The concession granted the IEC the right to set tariffs, which are approved by the Ministers of Energy and of Finance. This is a significantly different rate-setting system than that in the United Kingdom or the United States. In the latter countries, the regulated firms request a rate change, while in Israel until recently, the utility changes the rates, and the newly changed rates are approved by the government. This is particularly different form the United States, where an independent regulatory commission conducts a litigious process held in full view of the public. By its concession, the IEC is entitled to set rates so as to meet its obligation to pay out dividends at a prespecified annual rate of 8 percent of shareholders' capital. Shareholders' capital is defined as the inflation-adjusted initial investment, excluding retained earnings. In the case that actual performance exceeds the previously mentioned threshold, the concession specified additional instructions for distributing dividends. The IEC developed and grew in an institutionally stable environment until the end of the 1980s. But, while the rules of the game were well known and conducive to good economic performance, the results were not quite as might have been expected. This was due, at least in part, to the extremely rapid growth of the Israeli economy and the associated electricity consumption (see Table 5.1). To put the performance of the IEC in proper perspective, several characteristics of Israel's early history and geopolitical situation are noteworthy. Israel survived its war of independence with meager military means. Israel's economy during these early years of the state's existence was agricultural, unindustrialized, and burdened with high rates of population growth, mainly due to immigration. Indeed, in its early years of existence Israel was a member of the developing world. The early immigrants to Israel, as well as later the immigration waves, may be best characterized as refugees who arrived with basic needs for food and housing and without the financial resources to match. During the early 1950s, Israel was troubled with building an economic base for future economic growth, while establishing a defence establishment and providing basic housing for the masses of immigrants (see Carmon and Czamanski 1992; and Tables 5.2 and 5.3).

65

Israel

Table 5.1 Basic Statistics of IEC, Pre-Restructuring Years Year

Installed Capacity (MW)

Total Consumption (MWh)

Load Factor

Capacity Factor

(%)

(%)

1950

99

418

53.7

59.6

1960

410

1,885

60.8

62.3

1970

1,232

5,852

68.7

62.7

1980

2,737

10,864

67.4

51.3

1981

3,041

11,191

67.0

50.2

1982

3,361

11,790

68.1

48.4

1983

3,711

12,556

65.2

45.4

1984

4,061

12,856

65.3

41.4

1985

4,061

13,517

66.7

42.2

1986

4,061

13,957

62.8

43.6

1987

4,061

15,419

60.3

48.1

1988

4,061

16,920

60.8

52.6

1989

4,295

17,951

60.2

54.7

1990

5,065

18,333

60.9

51.5

1991

5,835

18,781

52.4

46.5

Source: The IEC, Annual Statistical Report, 1990, 19-20; 1993, 8-11 (in Hebrew).

By the early 1980s, Israel was classified by the OECD as a newly industrialized economy. By 1996, its per capita GDP reached U.S. $17,000, and in terms of buying power parity, its GDP per capita reached almost U.S. $20,000, thus placing it among the twenty leading world economies. Its economic base has become highly industrialized. Its exports had a high content of value added. It has become a center of high technology industries, and many leading firms have established research and development centers in Israel. In the early history of the country, high and volatile rates of growth in the demand for electricity had to be met while building a modern electricity system. Israel's geographic and political isolation meant that the electric system

Privatization and Restructuring of Electricity Provision

66

Table 5.2 Israel—Some Basic Statistics

Year

Population (000s)

1950

1,370.1

5,397

1960

2,150.4

8,971

1970

3,022.1

14,793

1980

3,921.7

19,022

1981

3,977.7

19,569

1982

4,063.6

19,478

1983

4,118.6

19,611

1984

4,199.7

19,641

1985

4,266.2

20,176

1986

4,331.3

20,764

1987

4,406.5

21,722

1988

4,476.8

22,137

1989

4,559.6

22,012

1990

4,821.7

22,634

1991

5,058.8

22,649

1992

5,195.9

23,374

1993

5,327.6

23,534

1994

5,471.5

24,458

Per Capita GDP (constant 1994 NIS)

Source: Israel Bureau of Statistics, Annual Statistical Report, 1995, 22.

had to supply all the country's needs while maintaining unusual reserves for surges in demand and unexpected supply failures. To this day, Israel's electric system suffers from an absence of noticeable interconnections with the neighboring systems. A tradition of self-reliance created a dependency on the IEC and its central planning abilities. The absence of own energy sources, Israel's isolation in the world, and distance from "friendly" sources of fossil energy created a particular profile of installed capacity, almost exclusively coal based (see Table 5.4). It also led to an emphasis on generating capacity at the ex-

67

Israel

Table 5.3 Israel—Electricity Consumption and GNP, Recent Years Year

Electricity Consumption

Electricity Consumption

(kwh millions)

(annual % change)

GNP

GNP

(1980 NIS in 000s)

(annual % change)

Electncitv Consumption per Thousand NIS GNP (annual % change)

1985

13,517

5.1

128,245

3.8

1.2

1986

13,957

3.3

133,033

3.7

-0.5

1987

15,419

10.5

140,350

5.5

4.8

1988

16,920

9.7

143,297

2.1

7.5

1989

17,951

6.1

145,160

1.3

4.7

1990

18,333

2.1

151,837

4.6

-2.4

Source: Data compiled by author. pense of quality of service. Since the 1980s, quality of electricity services has become a major issue as well. By the late 1980s, the IEC has become and economic powerhouse within the Israeli economy. In terms of output and in terms of employment, it was consistently ranked as the largest corporation. With size came political power. The union of electricity workers was perceived by all politicians to be the most powerful political organization. Occasional proclamations by Ministers of Finance or Energy to do away with free electricity allocations to electricity workers, or to reform the retirement-fund financing methods met with threats of strikes and electricity blackouts. While the country's economy was increasingly efficient, the IEC remained an inefficient electric system. By the late 1980s, the IEC employed more than 10,000 workers and served 156 customers per worker of the IEC. The system experienced some ten hours of service interruptions annually. These indicators of performance place the IEC among the less-developed electric systems of the world. The World Bank's equivalent standard targets of acceptable performance for lagging electric systems in those years were 150 to 250 customers per worker and seven hours of blackouts per year (World Bank 1994). EARLY REFORM EFFORTS The "good life" of the IEC as a vertically integrated monopolist began to change unexpectedly in the late 1980s. World record-breaking hyperinflation

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Privatization and Restructuring of Electricity Provision

Table 5.4 Installed Capacity by Power Station and Year (MW) Year

Haifa

Redding

Eshkol

Maor David

Ruthenberg

Other

1950

60

36

1960

84

176

150

1970

516

390

300

26

1980

482

568

1,212

475

1981

482

528

1,206

350

475

1982

432

528

1,206

700

495

1983

432

528

1,206

1,050

495

1984

432

528

1,206

1,400

495

1985

432

528

1,206

1,400

495

1986

432

528

1,206

1,400

495

1987

432

528

1,206

1,400

495

1988

432

528

1,206

1,400

495

1989

426

528

1,206

1,400

735

1990

426

528

1,206

1,400

550

955

1991

426

528

1,206

1,400

1,100

1,175

3

Source: The IEC, Annual Statistical Report, 1995, 10.

led to drastic monetary and related policies. A law regulating price increases, especially in sectors given to government control, was passed. Tariff adjustments were hindered, and as a result, the IEC reported losses in two consecutive years, 1990 and 1991. On 28 October 1990, the Ministers of Finance and Energy appointed a public committee to study the IEC's rate setting—the Fogel Committee. The committee was mandated to decide on proper objectives and principles of rate setting and to establish methods for setting fair and equitable tariffs. Representatives of the ministries, of the IEC, and of the general public were members of the Fogel Committee. The Fogel Committee submitted its findings one year after its appointment, and they were instituted in June 1992. The proposed changes represented the

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first major institutional change in the environment within which the IEC has had to operate. Two types of tariff adjustment mechanisms were set into motion. Automatic adjustments were to be triggered by economic forces over which the IEC has no control. Periodic, nonautomatic changes in tariffs were to be instituted based on "recognized costs" and based on an evaluation of the extant conditions. On the face of it, Israel has undergone a metamorphosis to a U.S.-type regulation, but without a public regulatory commission. In its place, the "adjudication" of tariffs was to be administered by the Ministers of Finance and of Energy. A clearly established method of tarrif setting was to limit the need for, indeed, do away with, a regulatory commission. The "recognized costs" were defined by the Fogel Committee as consisting of the typical variety of factors of electricity production, including, capital servicing costs, fuel costs, operating and maintenance (O&M) expenses, and the cost of purchased electricity.1 The fuel adjustment clause was based on the prices of coal, heavy oil, and gas oil. The adjustments were to follow publication of changes in the relevant prices by the Ministry of Energy. O&M expenses were to be adjusted with the periodic publication of changes in the consumer's price index. While all components of the Fogel formula were acceptable to the IEC, the treatment of capital service charges and a price-cap type of tariff-reduction mechanism constituted a major and interesting change in the relationship between the IEC, its stock owners, and its customers. The capital-servicing cost component included depreciation and return to stock owners. Depreciation was set on current, inflation-adjusted values and not on historic costs. The life of the equipment was calculated based on "engineering," or planned, life of the equipment. The immediate result of this decision was that the IEC's depreciation expense account became much smaller, and in the IEC books, the account was overstated by some 20 percent. Generally, the treatment of historic costs is a contentious issue at the time of reforms. The return to stock owners was set at 5.33 percent, so as to reflect the structure of capital, onethird equity and two-thirds debt, and its real projected costs, 7.5 percent for equity and 4.25 percent for debt. One component of the Fogel Committee recommendations the IEC did not accepted gracefully. It was forced to strive for efficiency improvements until the expiration of its concessions in 1996. The real price of each kwh of electricity was to be decreased in real terms by 1.5 percent in 1991 and by 2 percent per year until 1996. The adoption of the recommendations led to a series of price increases. In all, the resulting prices of electricity in Israel were still extremely low, and this at a time the IEC had forecast major load growth until the year 2000 (see Table 5.5). High rates of load growth, coupled with relatively low prices and with low service standards, are the backdrop to the serious discussions of restructuring and privatization that took place in Israel starting in 1992. The occasion for the public discourse was the encroaching expiration of the original concessions granted the IEC in 1926 for a period of seventy years.

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Privatization and Restructuring of Electricity Provision

Table 5.5 Average Tariffs and Projected Consumption Growth Rates

(cents/kwh)

Compound Growth 1992-1995

Compound Growth 1995-2000

17.68

7.76

6.4

7.7

Agriculture

17.34

7.61

3.6

3.8

Commercial

15.56

6.83

6.6

5.0

Industrial

15.13

6.64

6.1

6.4

Water Pumping

14.45

6.34

Total

16.45

7.22

1991 Tariff

1991 Tariff

(agoroth/kwh)

Households

Sector

.04 5.7

0.0 5.9

Source: Israel Energy News, Annual Statistical Report, various years. THE VARDY REFORM PROPOSALS AND THE CZAMANSKI DRAFT LEGISLATION PROPOSALS As a first step in the consideration of the practical options that stood before Israel's government, the Ministers of Finance and Energy appointed a public commission to study, evaluate, and recommend possible actions concerning the future of the electricity system in Israel. Such commissions are common in Israel. They serve as the sounding board and testing ground for new ideas. The commission included business and civic leaders. At the head of the commission stood Joseph Vardy, a business leader and ex-director-general of the Ministry of Energy. Its composition and mandate assured the politicians that the recommendations will be balanced. Since the commission was to hear a variety of positions on the issues, including those of the IEC and of various outside electricity experts, it was presumed that its recommendations will serve as guidelines for policy making and that they will be acceptable to the general public. The Vardy commission's charge was to recommend whether the concessions to the IEC should be extended, and if so, under what conditions. A clear answer to the first question was mandated by the terms of the original concessions. In addition, should the commission decide to recommend termination of the concessions, it had to recommend alternative courses of actions. The letter of appointment specified a series of questions, including • Should the IEC remain the sole provider of electricity in Israel? • Should the IEC be split into a number of entities? • Should the state of Israel license independent power producers?

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71

The issues were practical and pointed. Since the issues at the backdrop of the questions are complex, the ministers left open, at the discretion of the commission, to consider other issues that it might choose to tackle. Within a year, on the last day of 1992, the Vardy commission submitted a short document (thirtyfive pages). While intentionally vague on many issues, the document was clearly revolutionary. The document included twenty-five recommendations. First and foremost, the commission recommended the legislation of a new electricity law that would replace the concessions of the IEC. The new law would not grant exclusive rights to the IEC, and indeed, competition would be the means to achieve improvements in efficiency in those areas in which competition is feasible. In other areas, the IEC would remain a monopoly. Nowhere in the Vardy report was it stated what type of competition is suitable for the small and isolated electricity system of the state of Israel. The public discussions and press interviews that were granted by Vardy did not clarify the issue. Even in private, closed-door discussions, it was not possible to pin down the commission members to a clear statement of principles. Was it the intention of the commission to introduce full-fledged wholesale and retail competition into the electricity market in Israel? It is clear that wholesale competition was indeed envisaged. The commission proposed the introduction of independent power producers. In language borrowed from the U.S. PURPA legislation from the late 1970s,2 the commission recommended that such producers will promote greater efficiency. However, in the same paragraph, the commission stated that these producers will emphasize "clean" and renewable energy. It seems that it was the judgment of the commission that wholesale competition, especially when limited to specific technologies and fuel sources, might be politically acceptable. And yet, the door to retail was not shut. In paragraphs that described the nature of the licenses that are to replace concessions, there are clear indications that should the political will permit it, there would not be any institutional barrier to retail competition. Indeed, there is a clear indication that the transmission and distribution licenses will have a common-carrier character. The commission devoted much thought to the problem raised by common government ownership and regulation of the electricity system. Until the Fogel recommendations concerning pricing of electricity, there was no de facto regulation of IEC. This is despite the fact that the concessions granted such authority to the government. It was generally accepted in Israel that the interests of IEC were equivalent to the public interest. The Vardy commission devoted much thought to regulation and recommended that a public utilities commission be established. The commission was to be independent and to perform its duties in full public view. The British model was rejected in favor of a U.S. type of regulation. The Vardy report received full public viewing in the early weeks of 1993. It did not receive accolades or major criticisms. The IEC stated publicly that competition is not workable in Israel for several reasons. Above all, the size of

72

Privatization and Restructuring of Electricity Provision

Israel's electricity system is too small to support several business firms. Indeed, economies of scale are still to be exploited. More important, the marked absence of interconnections with neighboring systems makes the system vulnerable, and no market system is capable of regulating the constant matching between demand and available supply. In addition, high rates of annual growth place special demand on the system's planners, again, a task that the market cannot fulfill. Public attention was not concerned with these issues. Instead, it focused on the possibility that a new electricity law might do away with free electricity allocations to the employees of the IEC. Behind the scenes, a major political effort was taking place to persuade the politicians to abandon all thoughts of replacing the concessions. Indeed, during the following months, while the Minister of Energy was pursuing practical steps to implement the Vardy recommendations, the leaders of the IEC's labor union extracted a promise from the Prime Minister, whose father was an early IEC employee, that nothing will in fact change. At any rate, the deadline for passing the appropriate legislation seemed to be very far away, in March 1996. Still, before the Vardy commission submitted its recommendations, the Minister of Energy appointed the author, Daniel Czamanski, as his adviser and charged him with studying alternate practical means to implement the Vardy recommendations and to prepare draft legislation as needed. A generous budget with a separate line item in the government's budget was allocated for the years 1993-1994. A task force was organized, and a work plan was prepared. The task force was under the constant supervision of the director-general of the ministry and monthly progress reports were submitted to the minister. The Czamanski task force submitted its final report at the end of 1994. The principles of the Vardy report served as guidelines for the examination of alternate possible structures of the future electricity system and of the steps that would need to be undertaken in order to implement a full-fledged marketoriented electricity industry. At the outset, the task force identified eight objectives in response to undesired conditions that afflicted the IEC. In particular, the IEC was characterized by the task force as a conservative organization that lacked motivation to increase efficiency through technological or organizational innovation. The absence of organizational flexibility made response to challenges due to demand growth difficult and efforts to improve service standards, albeit not very ambitious, all but nonexistent. The objectives included the following: • • • • • •

The prices of electricity should reflect precisely the true costs. Service to customers should improve. Reliability must increase. Efficiency must increase in all parts of the system. Innovation must be promoted. Renewable and clean electricity production should be promoted.

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• Electricity conservation should be promoted. • The system should be flexible. The task force set out to examine alternate organizational structures of competition, associated systems of licensing and ownership, systems of regulation, and requisite legislative apparatus. From the outset, practical issues of transition were examined in the context of each alternative. Criteria of evaluation were set up as a backdrop for the consideration of the alternatives, including prospective benefits, costs, implementation problems, and legislative issues. The task force set up a discussion venue with the IEC, and a joint committee that included the senior managers of the IEC started working. Experts from various countries were invited to participate in the discussions, and a detailed study of the experience in various countries was undertaken. By mid-1994, the task force submitted its final recommendations for the government's consideration and prior to drafting the requisite legislation. The recommendations pertained to • • • •

The future structure of Israel's electricity industry. The licensing of electricity activities. The structure and operation of the public utility commission for electricity. The steps to be undertaken in the transition process.

It was the major conclusion of the task force that to achieve these various objectives, Israel should strive to implement full competition in the wholesale and retail electricity markets and extensive privatization. Privatization was to follow restructuring and the establishment of clearly defined rules for licensing and regulation of the system. It was the task force's opinion that prior to the introduction of private interests, new institutions need to be set up so that the interaction of the various actors in the industry will be clearly structured. The restructuring was to be implemented in three steps. The first step was to take place in 1996 with the expiration of the concessions to the IEC. The second step was to be implemented in the year 2000, or very soon thereafter. The third step was to take place anytime after Step 2. Figures 5.1 and 5.2 describe the actors in the electricity industry following Step 1 and Step 2. The purpose of the intermediate step was to prepare the ground for the restructuring. At the time that the task force recommendations were written, the IEC was a single business entity. Its internal organization was dictated by production process considerations and not on the basis of profit centers, as would be suggested by business orientation. In the United Kingdom, unlike in Israel, prior to the restructuring and privatization, the organization of the industry matched its future structure. The restructuring in the United Kingdom consisted of distancing and severance of the umbilical cords among existing business units. In Israel, the business units had to be created as part of

Figure 5.1 Proposed Structure of Israel's Electricity System—Intermediate Stage Public Utility Commission Electricity

Distribution Holding Company

Northern Distribution Company

State of Israel

Ministry of Energy and Infrastructure

Electricity Council

Israel Electric Company

Transmission Company

Southern Distribution Company

Coal Supply Company

Dan Distribution Company

New Power Producer

Jerusalem Distribution Company

New Power Producer

Existing Power Stations Organized as Profit Centers

Power Plant Planning and Construction Company

Internal Services Company

New Power Producer

74

Independent Power Producer

Independent Power Producer

Independent Power Producer

Independent Power Producer

Figure 5.2 Proposed Structure of Israel's Electricity System—Year 2000 Public Utility Commission Electricity

Distribution Holding Company

Northern Distribution Company

Ministry of Energy and Infrastructure

State of Israel

Electricity Council

Israel Electric Company

Existing Power Producer Organized as Companies

Transmission Company and Power Pool Coal Supply Company

Existing Power Producer Organized as Companies

Dan Distribution Company

New Power Producer

Existing Power Producer Organized as Companies

Jerusalem Distribution Company

New Power Producer

Southern Distribution Company

Power Plant Planning and Construction Company

New Power Producer Internal Services Company

75

Independent Power Producer Independent Power Producer Independent Power Producer Independent Power Producer Independent Power Producer

76

Privatization and Restructuring of Electricity Provision

the reform. At this stage, no changes in ownership structure was proposed. At the margin, it was proposed to introduce several independent, privately owned power producers (see Figure 5.1). Such an action was already being considered by the government to spur the IEC to use renewable and clean energy sources. Several new companies and profit centers were proposed. A new distribution holding company was to be created as an owner of several regional distribution companies. The holding company would remain in government ownership, though separate from the IEC. The holding company would be organized by reference to and consistent with the electric topography of the system. The IEC would remain as a holding company of all the other existing activities that it performed to that day. Existing power stations would be organized as profit centers. The task force considered organizing the power stations as companies. IEC management raised the issue of the system's size and the possible damage that would be sustained by not exploiting the extant increasing returns to scale in generation. The task force brought evidence from a variety of international studies. The discussion reached the pages of the daily press and electronic media and thus threatened the credibility of the task force. To improve the probability that the entire reform package would be accepted, it was concluded that a profit-centers solution would be adopted, a compromise was struck, and the IEC employed an international consulting company to implement the idea. Thus, a first major compromise was reached with the management of the IEC. The task force recommended that all new power plants will be organized as separate companies, not as profit centers. Transmission and load management was to be organized as a company, but wholly owned by IEC. The decision not to separate the transmission company from IEC was also the result of public debate spawned by the IEC concerning the inability of the IEC to assure reliability of the system without it controlling transmission. The IEC emphasized the size of the system, its high rates of demand growth, and the absence of interconnection with neighboring systems as conditions that preclude reliance on market forces as regulating mechanisms. The IEC had no objection to organizing various ancillary services as separate subsidiary companies of the IEC. Informal acceptance and agreement concerning the intermediate stages of the reform seemed at the time a critical prerequisite to the submission of the legislature in 1996. The structure of the system as proposed for the intermediate stage is not sufficiently adopted to the introduction of private interests. The presence of private interests within the context of the intermediate structure would increase, not reduce, the need for the regulator. Indeed, under this scenario, the efficient performance of the system would be assured principally by the regulatory authority. An efficient, profit-maximizing, government-owned IEC, together with a separate but government-owned distribution company, would be a powerful economic and political force to contend with, even in the presence of several small, independent power producers. The IPPs would provide a yard stick for the regulator, but

Israel

11

the regulator will not posses the power to prevent cross-subsidies, and thus both wholesale and retail competition would not be feasible. The proposed structure for the year 2000 was intended as a second step and one that would bring the system close to that in the United Kingdom on the eve of privatization (see Figure 5.2). Three separate, government-owned entities were envisaged. The distribution holding company would be under the intermediate proposed structure. The transmission and load-management functions would be organized as a separate government-owned company. The existing power plants would constitute a number of separate companies, all owned by the IEC. The IEC would become a holding company. It would also own new power plants, each organized as a separate company, and the various ancillary services would be organized as separate companies. The number and size of privately owned, independent power producers would be greater than under the intermediate structure. The proposed structure is amenable to the introduction of competition, both at the wholesale and retail levels. The transmission company would operate a power pool and a forward market for electricity. The transmission company would become a common carrier, and as such, would not be allowed to own the electricity that it transmits. This requirement created a technical problem, inasmuch as the transmission company would have to regulate the system load, and to this end, it would require some generating capacity. Therefore, it would have to introduce into the system at least some electrical energy that it in fact owned. Several legislative apparati were proposed and examined, but no satisfactory solution was found. Under the proposed final structure of the system, the Ministry of Energy would continue to be responsible for the existence and proper functioning of Israel's electricity system. The Minister of Energy would design the electricity policy, implement the new electricity law, award the appropriate electricity licenses, and supervise the preparation of load forecasts and future capacity needs. Because of the relative shortage of land in Israel and the government's ownership of most of the country's land, it was proposed that the Ministry would be responsible for securing land for the construction of future electric facilities. A major effort by the task force was devoted to the study of alternate regulatory philosophies and regulatory organizations. The proposed regulatory regime consists of a U.S.-type of regulatory commission operating under strict guidelines and a "sunshine clause." Unlike the U.K. alternative, it was proposed that all deliberations of the commission and all its decisions would be transparent and open to public scrutiny. The commission would be a statutory body. The five commissioners would be appointed for prolonged periods and thus freed from political pressures. The commission would have at its disposal a professional staff. Because of its independent status, the salaries of the professional staff would reflect market wage rates and not wage rates of government workers. Its budget would be levied from the regulator as a predetermined percentage of rates and according to the size of the regulated body.

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Privatization and Restructuring of Electricity Provision

It was the opinion of the task force that the regulatory doctrine must affect the nature of the electric system, and in particular the extent to which the selfinterest of the various actors can be disciplined by marketplace interactions. Of course, some parts of the system were to remain a natural monopoly. The regulation of these would have to be consistent with the regulation of the rest of the system. While the task force did not specify the precise regulatory doctrine to be exercised by the commission, it did state its preference. It rejected price-cap regulation during the first years of the reforms. It proposed the adoption of U.S.-type fair rate-of-return, but rejected the setting up of performance or conduct standards. Price-caps were to be adopted much later, with the advent of extensive competition. An unusual and functionally meaningless council would be established. In light of the diminished political clout of the politicians in the life of the electricity system, the council's purpose was to appease the thirst of the Minister of Energy to appoint individuals to politically meaningful positions. The council would consist of twenty to thirty individuals who would meet several times a year to consider policies and make recommendations to the Minister. THE ELECTRICITY LAW OF 1996 The Czamanski task force proposals were submitted to the Minister of Energy in the summer of 1994. The long time period that remained until the expiration of the IEC concessions in March 1996 made possible extensive discussions to be held in the Ministry of Energy and the government, before the proposed law would be brought before the Parliament. A full year of parliamentary debate was envisaged. The public debate that took place did not focus on the prospective benefits and costs of the restructuring, nor was it concerned with implementation issues as envisaged by the planners of the reforms. The debate made clear that the proposed reforms threatened the political power, clout, and integrity of the electric company workers' union. Explicit threats to shut down the electric system were made on various occasions. Each political meeting in the presence of the Minister of Energy and/or the Prime Minister was exploited to threaten the labor government of the late Prime Minister Rabin. The future of the reforms was uncertain. Before the Labor Party primaries, Rabin was duped by the leaders of the union to sign a short agreement that gave the union a veto power on any decision to restructure the IEC. The government debated the proposed law and finally in February 1996, it was submitted to the Parliament for a quick approval. The Israeli Electricity Law of 1996 was in fact entirely rewritten by the Chairman of the Finance Committee of the Parliament during a series of marathon sessions, most of which were not attended by any members of the committee. The resulting law (see the schematic structure of the law in Figure 5.3) skirted the major obstacles that might arise on the way to implementation by creating an apparatus that makes the reforms possible, but not immediately

79

Israel Figure 5.3 Schematic Structure of Israel's Electricity Law, 1996 annual report Minister of appointment and budget approval Energy

rules and regulations license conditions transitions rules

DirectorGeneral

work permits arrangements for 10 years

Public Utilities Commission

service quality

tariffs

licenses Tariffs and service standards

permit to occupy land

development plans

essential service providers private producer

unified license

trade

trade

data and reports

generation

distribution )

transmission

generation

mandatory. As proposed by the task force, the Minister of Energy can issue licenses for the generation, transmission, and distribution of electric energy. The Minister will be responsible for preparing development plans. These will serve as guidelines for issuing licenses. However, until the year 2006, the IEC will hold a cluster of licenses that will permit it to continue to function as before. Additional licenses to produce electricity will be issued to private producers of electricity to the extent that the total capacity of private production does not exceed 10 percent of the IEC capacity. The ten-year grace period that was allocated until the full implementation of the reforms enables the IEC and the regulatory commission to prepare for

80

Privatization and Restructuring of Electricity Provision

the restructured world. In fact, the task force envisaged transition problems that would require a period of time for adjustment. It is unclear how much time is sufficient for this purpose. The requirement that the IEC operate under separate licenses for the various activities would mandate a major reorganization and finally formation of new business entities. It is doubtful that the IEC could fulfill such an obligation in a short time period. The absence of middle management, a centralist corporate culture that placed all major decision powers in the hands of the top management, and profit seeking as a central motivation precluded rivalrous business behavior. The absence of a regulatory tradition and professional staff means that new individuals need to be trained and that behavior norms must be developed. The regulatory organization was set up with the passage of the law. It was charged with immediate review of the existing tariff structure. It is unlikely that this first task of the Commission will be accomplished in the first three years of the Commission's activity.3 In late 1997, the Commission held a day-long conference to begin public debate with the IEC concerning Israel's regulatory agenda. It is noteworthy and somewhat surprising that the issue of fashoning institutions that will provide incentives for economic behavior has emerged with such a force and so early in the life of the Commission as the main issue. The regulated and the regulators recognized the possible tradeoffs that exist in the context of alternate patterns of restructuring, private capital, and properly adjusted regulation practices. Each scenario creates a different pattern of incentives and possible results. While the possibilities are clearly recognized, the choice is not easy. Actions by the Commission are being challenged by threats of strikes by the union of IEC workers. The union has mandated its management, in other words, the IEC's management, to cease all contacts with the regulators due to the Commission's untoward statements and actions. The union is challenging the Commission's rights to make certain types of decisions in courts of law. It will be another few years before it is clear whether Israel is on the road to reforms that will improve efficiency. NOTES 1. It is noteworthy that, while independent power producers (IPP) were all but nonexistent in Israel at the time of the Fogel Committee, these were times of extremely fast demographic and economic growth. Ground was prepared for the eventuality that IPPs will have to supplement the IEC generating capacity to meet load growth. 2. In particular, the PURPA itself (see Chapter 6, pp. 83-89). 3. As these lines are being written, some eighteen months have passed since the passage of the law. No significant order has been issued by the Commission. It is doubtful that the average consumer of electricity in Israel is aware that a regulatory body has been established.

6 Incremental Restructuring in the United States

There were many developments that preceded the contributions of Thomas A. Edison to the modern electricity industry. Sir Humphrey Davy invented the arc light in 1808. Michael Faraday produced the dynamo in 1831. Many others experimented and contributed to the development of the required technologies needed to produce and transport electrical energy. However, Edison was the first developer of the concept of a central power station and a system for delivering energy for lighting, heating, and powering at distant locations. In 1882, his Pearl Street Station in New York City began serving eighty-five customers with 400 lamps. Today the U.S. electric system is in fact many different systems. The size of the country mandated that electricity supply start in many locations and by a variety of individuals and organizations. Interests, motivations, and circumstances were varied and thus the resulting structures were varied as well. To this day, alongside privately owned companies, the United States has systems owned by the federal government and by municipal governments, as well as cooperatives. THE EARLY EVOLUTION OF THE U.S. ELECTRIC INDUSTRY From the start, the electric industry in the United States was characterized by competition that came from the older gas lighting companies and a variety

82

Privatization and Restructuring of Electricity Provision

of scattered new electricity producers. While Edison relied on direct current and was thus limited to transmission over short distances, Westinghouse Electric developed another approach that relied on alternating current produced at 1000 v, and that could be transmitted over longer distances and later could be transformed to 100 or 50 v for final use. With the developments of Westinghouse Electric, various cities began to grant franchises to private companies. Often these were multiple and competing franchises for single purposes, such as street lighting, home lighting, tramways, or commercial power. A variety of technologies were used. As a result, the last decades of the nineteenth century witnessed a rapid growth in the electric industry in the United States. At first, the number of companies grew. They expanded in terms of capacity and geographic scope so as to benefit from economies of scale. Quickly, the number of companies started to decline as amalgamations became a popular means to achieve load diversity and to forestall competition. Capital shortage to finance the increasingly capital intensive expansions led to the use of long-term general mortgage bonds. Financial institutions, concerned for the financial security of the bonds, required assurances of survivability of the new companies. The nascent industry began to seek protection mechanisms from the short-lived, city-granted franchises. Industry leaders, among them Samuel Insull of Chicago Edison, sought protection from the states in the form of regulation. After 1900, investor-owned electric operating companies became regulated by state commissions. The need for financing the expansion of the operating companies led to increasing involvement of engineering and equipment firms in the ownership of operating companies. Instead of cash payments for equipment and services, frequently they received securities. Holding companies were formed. By the 1920s, the rate of formation and expansion of holding companies reached tremendous proportions. By 1932, eight companies controlled some 73 percent of investor-owned utilities. In 1928, the Federal Trade Commission began to investigate financial abuses. The stock market crash of 1929 and the Great Depression led to the dismemberment of the holding companies through the Public Utility Holding Company Act (PUHCA) of 1935. Concomitantly, the Federal Power Act (FPA) of 1935, ostensibly a tool to regulate the interstate sale of electric energy, created an implied regulatory compact between state public-service commissions and electric utilities. From the inception of the electric industry in the United States, municipalities owned electric systems within their jurisdictions, the so-called "munies." Municipal ownership expanded greatly during the 1930s. In fact, by the 1930s, the number of munies exceeded the number of investor-owned companies, albeit munies were smaller than private utilities, both in terms of number of customers and installed capacity. Rural electrification became an issue during the Roosevelt administration years. At the time, only about 10 percent of farms had access to electricity. Relatively low profitability of supplying electricity to low population-density

Incremental Restructuring in the United States

83

areas meant that investor-owned companies were slow to enter these markets. Their reluctance to electrify rural areas and the need for major investments for hydroelectric projects brought the federal government to establish the Rural Electrification Administration and such marketing organizations as the Tennessee Valley Authority and the Bonneville Power Administration (BPA). The activities of the Rural Electrification Administration were formalized by the Rural Electrification Act (the Norris-Rayburn bill) of 1936, which led to low cost loans as a means to finance farmers' electric cooperatives. There are five federal power administrations today.1 Each administration transmits and markets power within its assigned area. They are supplied by a variety of electric energy sources. WAPA, for example, markets power supplied by the federal Bureau of Reclamation and the U.S. Army, which operate some fifty-one hydroelectric plants in the WAPA service area. No additional major institutional changes took place in the U.S. electric systems until the mid-1970s. Following World War II, improving generation technology resulted in continuous and significant decline in electricity prices. Between 1945 and 1965, average plant size increased fivefold. During the same time, average heat rate and the incremental cost of generating plants declined by 37 percent. Nominal prices declined by 9 percent during a period that the U.S. consumer price index increased by 75 percent. Concommittantly, residential consumption per household increased by more than 150 percent. From the mid-1960s and until the beginning of the energy crisis in the early 1970s, electricity prices remained stable (see Table 6.1). However, uncertainty concerning future demand and the cost of installed capacity began to rise (see Table 6.2). Return on equity of investor-owned electric utilities along with price-earning ratio of their stock declined continuously, both absolutely and in relation to the price-earnings ratio of industrial firms. By the mid-1980s, public environmental concerns led to major reshuffling of optimal expansion plans of utilities. Environmental pollution by fossil fuel plants became a major public concern. Nuclear power plants were especially vulnerable to public attacks concerning possible environmental hazards. Their safety became a target. The financial stability of some utilities became an issue as they started to experience difficulties in meeting their financial obligations. In 1974, Consolidated Edison failed to pay dividends to its investors. In 1983, Washington Public Power defaulted on its bonds. And in February 1988, Public Service Company of New Hampshire went bankrupt due to its investment in the Seabrook Nuclear Power Station. THE FIRST STEP—BULK POWER SUPPLY COMPETITION By the early 1970s, the U.S. electric industry was highly diversified in terms of ownership structure and industrial organization. Large, government-owned and privately owned systems coexisted with small municipal, cooperative, and private systems. A variety of governmental bodies mandated and regulated its

84

Privatization and Restructuring of Electricity Provision Table 6.1 Average Yearly Electricity Prices in Ohio Year

Residential (c/kWh)

Commercial (c/kWh)

Large Users (c/kWh)

1960

2.562

2.558

.764

1961

2.547

2.503

.762

1962

2.569

2.517

.779

1963

2.546

2.465

.779

1964

2.501

2.420

.791

1965

2.447

2.241

.801

1966

2.397

2.196

.844

1967

2.370

2.172

.854

1968

2.322

2.129

.865

1969

2.272

2.100

.882

1970

2.269

2.072

.927

1971

2.330

2.166

1.000

1972

2.377

2.214

1.011

1973

2.425

2.262

1.051

1974

2.906

2.769

1.449

Source: D. Czamanski, J. S. Henderson, K. Kelly, et al., Electricity Pricing Policies for Ohio, The National Regulatory Research Institute, Columbus, 1997, 11.

behavior. Federal government set national policies and regulated interstate electricity transmission and sales. States regulated investor-owned utilities (IOUs) within their jurisdictions. Munies were subject to municipal government regulations. There was no clear-cut, single leading hand. Despite the extensive regulatory intervention, the overall structure of the industry, the presence of private ownership and interests, and its electric topography meant that market forces should have been free to mold and to influence the industry's performance. This in fact was not the case. In fact, the vast regulatory infrastructure that was created and refined over the one-hundred years of its existence succeeded extremely

85

Incremental Restructuring in the United States Table 6.2 Selected Financial Indicators, U.S. Electric Industry

1962

1965

1971

1974

1975

Return on Equity (%)

11.40

12.10

11.00

10.20

10.50

Return on Total Capital (%)

10.20

10.30

8.80

9.30

9.70

% Total Debt of Total Capital

52.20

51.80

54.70

53.30

52.60

Public Utility Bond Yield (Aaa)

4.37

4.50

7.72

8.71

9.03

Public Utility Bond Yield (Aa)

4.46

4.52

8.00

9.04

9.44

Interest Coverage Ratio

5.06

5.05

2.56

2.06

2.17

19.34

19.78

11.79

6.30

6.60

1.13

1.14

.65

.66

n.a.

Price - Earnings Ratio (P-E) Ratio P-E Utilities to Industrials

Source: D. Czamanski, J. S. Henderson, K. Kelly, et al., Electricity Pricing Policies for Ohio, The National Regulatory Research Institute, Columbus, 1997, 13.

well to protect the U.S. electric industry from the unpleasantries of rivalry and competition, just as it was intended to be by the early IOUs. Regulation on the Eve of Restructuring Most vertically integrated investor-owned utilities in the United States, were deemed by regulators as "affected with a public interest." This in fact was the essence of the regulatory compact that has existed in the United States since the early days of regulation. Retail rates are set through a three-step process: calculation of the utility's overall revenue "requirement," allocation of the revenue requirement among the various predetermined customer classes, and the determination of rates by reference to traditional rate making principles that include efficiency,2 fairness, and adequacy (Bonbright 1961; Khan 1970; NARUC 1992). It is universally accepted that the services of utilities should be provided at cost. This principle applies to the overall level of rates as well as to the various classes of customers. These classes, although traditionally determined, define the profit centers of all utilities. To set rates that reflect costs, cost of service studies have become the central element of the regulatory process. According to NARUC (1992), it is the purpose of cost studies to • attribute costs to various customer classes by estimating the contribution of these customer groups to the generation of costs.

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Privatization and Restructuring of Electricity Provision

• determine the means by which the incurred costs will be recovered from the various customer classes. • estimate the separate costs of the individual services provided. • determine the revenue requirement of a utility operating within a monopoly environment. • divide the costs incurred among the various jurisdiction within which a particular utility may be operating.

Until the 1970s, regulators did not concern themselves with the design of rates. They set the overall revenue requirement of the utility. It was the task of the utility to allocate the revenue requirement among groups of customers. This was done by reference to either "what the market would bear" or, alternatively, by reference to "value of service." In both cases, cost terms were defined in accounting terms of the engineering components of the system. Cost estimates were embedded, in the sense that they were based on monies that were actually spent for plant and operating expenses. These costs were then allocated, or distributed, among groups of customers based on cost causation. Since peak demand is the determinant of capacity expansions, the contribution of customers to peak demand became the standard for assigning capacity costs among classes. Fuel costs were allocated based on actual usage. Since some costs are invariant with demand and/or energy, a third category evolved to cover the variety of costs that are related to the very existence of a connection between a customer and an utility. These were termed customer charges. Three special rate making issues were frequently debated in regulatory proceedings: • treatment of joint costs • the incorporation of future costs • time-differentiated rates

Joint costs are present ubiquitously in all modern production systems. The problem arises from the use of a particular input in the production of more than one output without the ability to separate the contribution of the input to the separate outputs. Traditional capacity cost assignment based on contribution to peak demand is a classic example of such a problem. Though it is generally accepted that growth in peak demand prods the generation of capacity expansions, it is not disputable that the same capacity serves the needs of off-peak consumers. In traditional embedded costs, joint or common costs are allocated based on various "allocators," but remain essentially arbitrary. Though the regulator can initiate a rate-making procedure, it has been typical in the United States that rates are set for an indefinite period, and it is the regulated utility that intiates a rate case. Typically, such actions are motivated by increasing costs that may justify a rate increase. The use of historic testyear data as a basis for making rates that will hold in the future is particularly problematic during periods of inflation. Such was the case during the 1970s. In response to inflationary pressures, regulatory agencies were swamped with

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87

a multiplicity of rate cases. Their response was to include projected "future" data in rate making. Some commissions used future data alone, while other commissions used a combination of historic and future data. The economic conditions in the 1970s led to an attack on the very structure of rates. Traditional separation of rates into customer charges, demand, and fuel charges led to the universally adopted declining block-rate structure. The first quantity, or block, of electric energy was sold at a relatively high price per unit. The following block was sold at a somewhat lower price, and the last block was sold at a still lower price. Such promotional rates were well suited during periods of expansion. They were ill suited during periods of inflation. A variety of alternate structures were debated. Some proposed incentive rates that would increase over successive blocks. Others proposed level rates over the entire consumption range. Public Utility Regulatory Policy Act (PURPA)— The First Regulatory Reforms In some sense, from the perspective of investor-owned electric utilities, the energy crisis in the early 1970s came at the right time. In light of the financial difficulties caused by the increasing cost of new installed capacity, shortage of certain fuels, and concurrent prospects of growing demand, many in the industry saw the old regulatory compact as worn out and less than useful. The introduction of clean and alternate energy sources into the traditionally managed utilities was viewed by many as problematic. The IOUs were not set up organizationally to provide new services.3 The introduction through PURPA of IPPs as qualified facilities was a welcome solution. In the early 1950s, the U.S. generating capacity increased by some 5,000 to 10,000 MW per annum. The annual additions to capacity grew steadily until in the early 1970s it reached the record breaking level of almost 40,000 MW per annum. Then, the annual addition to capacity began to decline, and in 1980, it increased by only some 15,000 MW. By 1990, the annual addition declined to some 5,000 MW per annum. During the 1980s, the annual increase in the generating capacity of IPPs grew steadily, and by the early 1990s it was equivalent to that of IOUs. The PURPA-mandated change was achieved by changing the basic formula of the regulatory compact, and in particular by changing the rate-making mechanism. Traditionally, regulatory commissions set the price of electric power to customers so as to assure the IOUs a fair rate of return on their investments. The return was lower than in similar competitive markets, but it paid for the quiet life that characterized the business life in the U.S. electric industry until now. The stability was reflected in level and structure of rates and in the resulting demand that was easily forecasted and generally easily met by the IOUs. As the result of PURPA, the IPPs output had to be purchased by the IOUs at a new regulated price. In fact, PURPA mandated that the regulatory commis-

88

Privatization and Restructuring of Electricity

Provision

sions set monopoly prices for the output sold by the IOUs and a monopsony price for the electricity that they were to buy from the IPPs. This new price was set at the avoided costs of the IOUs. While traditional rates were set at average cost and often based on historic data, avoided costs, by definition, must reflect marginal cost and future test-year data. For large utilities that have exhausted already economies of scale in generation, the discrepancy between average and marginal costs should have been welcome as a means to further expand output. In fact, the conservatism of managements and their desire to continue doing business as usual meant that a new source of uncertainty was introduced. It was the prevalent opinion of IOU management that economies of scale were not yet exhausted and that new pricing policies would lead to further incentives to reduce new capacity additions.4 Another major thrust of the PURPA legislation was the promotion of conservation. Rate structures during the 1970s reflected past conditions and in particular the industry's effort to expand capacity in the 1950s through promotional prices. Thus, the typical rates had a declining blocks structure, and as monthly consumption grew, so did the price per kwh decline. Conservation was promoted by PURPA through prices that reflect the true cost of resources consumed in the production of electricity. In other words, PURPA introduced the principle of marginal cost pricing (though marginal cost pricing was mentioned only once in the legislation). Both the average level of electricity prices and the structure of the resulting tariffs had to be changed. PURPA introduced a major controversy into the tranquil U.S. regulatory world. A battle was waged between the marginalist views of the economists and legislators and the embedded or average-cost positions of accountants and engineers. The multiplicity of the resulting post- PURPA rate cases was the battleground on which the U.S. restructuring war was waged and eventually won. In the early years of the 1980s, the IPPs constituted a very small part of the electric industry in the United States (Aspen Institute 1996). It is doubtful that PURPA legislators envisaged a restructuring of the U.S. electric industry. But the mandated change in pricing policies to accommodate IPPs, within the context of existing industrial and regulatory structures, did eventually lead to the restructuring of the electric industry in the United States. Unlike in the United Kingdom and in Israel, the U.S. reforms were not spelled out clearly by policy statements of the government, nor were they the result of legislative initiative. The PURPA intentions were marginal in scope. Were policy makers in the United States interested in restructuring, they would have chosen to allow the IPPs to sell electricity to consumers directly and at market-determined prices. Restructuring did not represent the fundamental interests of decision makers. Retail competition was deemed difficult, if not impossible, by the Federal Energy Regulatory Commission (FERC). The main obstacle was the difficulty of removing potential subsidies in transmission and distribution rates—a prerequisite act to create a level playing field on which workable competitive interactions could take place. There are ob-

Incremental Restructuring in the United States

89

jective difficulties in calculating the precise cost imposed on a transmission or distribution system by a unit of electricity introduced into that system by an IPP at a particular location and consumed at another distant location. The difficulty stems from the nature of moving electric energy in a network of wires and concerns both joint costs and variable costs. Yet, the U.K. experience suggests that the imprecision that is introduced by averaging the various costs is compensated for, and significantly, by the efficiency that is gained by the act of restructuring. Post-PURPA IOUs remained vertically integrated utilities. PURPA did not even begin a process of restructuring. In fact, the major contribution of PURPA was to begin an earnest process of unbundling rates in the United States. Though generation was not to be separated from the wires business directly in the United States, the effort to make costs transparent and to remove cross-subsidies led to the conduct of the IOUs' business, as if the companies were separated into functional businesses. PURPA set the ground for a possible restructuring. THE SECOND STEP—UNBUNDLED RATES In the United States today, generation capacity can be owned by traditional utilities, by nonutility generators, such as the familiar qualifying facilities, and by wholly exempt wholesale generators. An imperative step toward the creation of competition, whether at the wholesale or the retail level, is the removal of price and other access barriers to the grid. To create an active wholesale market, it is imperative that prospective bulk power traders, buyers, and sellers can reach each other and that anticompetitive practices, such as discriminatory access and transmission charges, are eliminated. Furthermore, the cost of the transition to a competitive wholesale market must be low and equitably distributed. The evolution of unbundled utility rates during the late 1980s and early 1990s was the means to accomplish this, and it was bolstered greatly by the Energy Policy Act of 1992 and new FERC-mandated pricing rules. In effect, the new legislation mandated the creation of bulk power, or wholesale, market while FERC developed transmission access and pricing policies that made wholesale competition possible. The new unbundled rates precluded unfair competition in transmission. As a result, the price of transmission to a generating facility that is owned by the transmission company and to another generator has become undifferentiated.5 Initially, FERC has been applying its standard of nondiscriminatory tariffs to voluntary filings, such as the pricing proposal for a "Regional Transmission Group" of the United Illuminating Company (UI).6 UI operates within the context of New England Power Pool (NEPOOL), an organization in which members coordinate their planning and operations very extensively and in which all the demand in New England is met through central dispatching of all the generating facilities of the pool's members. The NEPOOL transmission grid has been constructed and financed as a series of individual transmission segments that

90

Privatization and Restructuring of Electricity Provision

are owned by the individual utilities. Yet, the system is operated as a single, region-wide "Transmission Company."7 The central idea of the UI proposal considers each vertically integrated utility as if it were functionally disaggregated. Each generating unit in the region, whether owned by a utility or a nonutility generator, is considered to be a separate generating company. In addition, each load center within the region is treated as if it were a separate local distribution company that receives wholesale electricity supply from various generating companies for distribution and sale to the retail customers within the geographic area of the load center. UI proposed to establish a regional transmission tariff (RTG tariff) for all New England utilities as an equitable means to allocate transmission system costs. The RTG tariff would establish uniform rates, terms, and conditions available to all generators throughout the region. The tariff would reflect the fact that the transmission grid must be planned and constructed to accommodate the maximum planned output of each generator. The tariff will compensate fully each utility that owns transmission facilities and will assess each generator in terms of the cost that the generator imposes on the system. The establishment of the RTG tariff requires a number of calculations. The first step consists of a calculation by the individual owners of transmission segments of the charges for transmission under the assumptions of traditional, uniformly applied, cost-of-service methods. As a second step, a region-wide transmission cost-of-service study will establish the sum of all rolled-in embedded costs of the transmission segments. Past studies have established that the utilization of the transmission system by each individual generator is dependent primarily on the impedance of the interconnected grid and is independent of the load level or the location to which it is supposed to be delivered. In other words, the percentage of the generator's output that flows on any particular transmission line segment on the grid is the same regardless of the generator's output, load level, load distribution, or the concomitant activity of other generators. Thus, the effect of each generator on the transmission system can be determined by examining the load flows associated with each generating facility based on a megawatt-mile method. Several load flow studies will be required to implement the RTG tariff proposal. In order to identify the character of the load flow of each individual generator within the region, a base-case reference load-flow study will be prepared. Each generating unit's characteristic load flows on line near the unit's location will be studied by comparing its load flows under specific conditions with the base case. Then, the regional loads will be scaled and balanced according to the amount of the change in the particular unit's load. After the load and generation amounts are balanced, the two cases will be compared and the calculated difference in the operation of the transmission system will reflect the unit's operations. The calculated contribution of each unit will then be allocated to the various transmission lines in the system and expressed as a percentage loading on each line.

Incremental Restructuring in the United States

91

Each transmission system consists of a variety of different lines. In overhead lines, the flow of power does not affect adversely a restricted interface. There are lines in which the flows of power either increase, or alleviate, the constraint on a restricted interface. There are also underground cables. It is necessary to adjust the contribution of generating units to system costs by accounting for the different types of lines owned by the utilities that constitute the regional system. In sum, the contribution of each generator to the system-wide transmission cost will be determined by multiplying the total, region-wide transmissionsystem revenue requirement by a particular generator's megawatt-mile effect on the system, divided by the megawatt-mile effect on the system of all the generators together. A similar set of calculations will be conducted to estimate the contribution of generators that are located outside New England and are utilizing the region's transmission system. The entire procedure will have to be updated periodically as the system is changed and upgraded over time. The UI proposal has a number of advantages. The rates charged individual generators for the transmission services within the region are comparable. No advantage is given to a generator owned by a utility that owns transmission lines. The costs of a transmission system are allocated fairly and equitably among those that contribute to the creation of the costs and according to their share. Each owner of transmission facilities is fully compensated for the costs imposed on its system. Proper price signals are provided so that future generatorsiting decisions will be made by accounting for the contribution of potential sites to the constraints over the interface. All costs, including those associated with loop flows, are accounted for, a situation that is not possible in the context of setting rates based on the contracted for flow paths. Finally, it is an administratively manageable pricing system. The proposed RTG tariff raises a number of issues that have been debated extensively in the United States and that heretofore have not received agreedupon answers. The proposal creates a fundamental change in the structure of economic interests. There are those who doubt whether the proposed tariff is a sufficient mechanism to ensure the impartiality of the pool operator. Some propose a new set of behavioral norms for an independent system operator (ISO). Others point out the great difficulties in balancing the need for the ISO's independence and the ability to be responsive, stable, and yet flexible, possessing substantive powers to influence the system and yet limited by regulations. Some suggest that the ISO is an element of public infrastructure and should not be privately owned. Its governance needs to reflect the public good. It is not clear how the governing body should be constituted and what rules should govern its conduct. Although ISO operations have been instituted in Texas and are being considered by a variety of transmission systems and pools, there is confusion concerning the issues and the arguments used to sort them out. The Harvard Electricity Policy Group is conducting a major simulation study to examine these and related issues.8

92

Privatization and Restructuring of Electricity Provision

Another set of issues concerns the maintenance and expansion of the transmission system. FERC began to explore an alternative to the pricing for transmission based on open access to the system. The use of tradeable transmission reservations through capacity reservations rates, along with the separation of the operations of the network from the ownership of its assets, would create a system in which market-based incentives would guide investment decisions in the transmission system. It is important to place such a prospective system in the context of the extant economies of scale and economies of scope that characterize the network. Obviously, these affect the design of the rules that would govern the efficient expansion and operation of the system. It would also require a fundamental restructuring of the regulatory environment within which transmission systems operate. THE THIRD STEP—RETAIL COMPETITION? The year 1996 was significant in the evolution of competition in the U.S. electric industry. Significant steps have been undertaken to promote wholesale competition and to explore the feasibility of extending it to the retail level. Several states passed restructuring and deregulation bills. Some have started practical steps to implement retail-wheeling as a form of retail competition. The first was Rhode Island, soon to be followed by California and Pennsylvania. Almost all the states are in various stages of conducting inquiries, hearings, forums, and preliminary drafting of legislation. At the federal level, FERC introduced Order 888 mandating open access to the national transmission system. A restructuring bill has been introduced in the Congress, and the White House is considering legislation of its own. Indeed, since 1996, the United States has set a course toward some form of restructuring. Unlike in other countries, the various initiatives in the United States fall under the rubric of deregulation, rather than restructuring. Several major issues are considered repeatedly in the context of all these actions: • How are market benefits of the increased competition best realized and distributed equitably among all customer classes? • How can a restructured market best provide safe and reliable service to its customers? • How should nondiscriminatory access to the market be assured for all power producers in a restructured environment? • How should restructuring ensure that market power in generation is not overly concentrated? • How should responsibilities for uneconomic assets and obligations be allocated among industry participants and over what period of time? • How can a restructured industry adequately accommodate environmental concerns and recognize the benefits of cost-effective, demand-side management and resource diversity?

Incremental Restructuring in the United States

93

• How should cost recovery for certain public policy programs, such as low-income rate assistance, economic development research, development and demonstration, and low-emission vehicles be addressed in a restructured industry? An exemplary set of answers to these and many other issues are provided by the Vermont initiative to restructure the state's electric industry. The initiative is interesting because of its explicit attempt to deal with a variety of issues and because of the environment within which the small Vermont system operates. It is part of the NEPOOL. The Vermont proposals go beyond the state's borders and relate to the entire pool. The plan provides for maximum choice for consumers while maintaining the level of safety, reliability, and access to service as before. The proposers of the plan claim that it can be implemented without increasing the cost of electricity to any group of customers, without increasing taxes, without reducing the return to investors, and without reducing the state's commitment to protecting the environment. The plan has four major objectives: • reduction of the price of electricity to all classes of customers. • promotion of technological innovation that would increase the value of electric services to customers. • maintenance of Vermont's standard of living through maintenance of the state's economic competitiveness. • maintenance of Vermont's control over its own future and prevention of an alternate restructuring plan from being imposed on the state from outside.9 The Vermont proposal includes a free market approach to generation and retail sales of electricity and a traditional regulation of the wires business. The transmission system, however, will include an ISO for the existing NEPOOL and a competitive exchange for bulk power. The distribution functions would become separate business entities that will operate as they have in the past, including continued responsibility for administering energy efficiency programs. As in the U.K. system, electricity customers will be able to contract for electricity from any licensed distribution company, including companies that do not own the wires that reach the customers' premises. At the backdrop of these proposals stands the conviction that decisions concerning the extent to which competition should be introduced depends on the nature of technology. Transmission and distribution are natural monopolies, and as such should remain monopolies that will continue to be regulated. No economies of scale exist in the relevant scale of generation and sales of electricity. Thus, the vertically integrated utilities will be broken up so that competition can be introduced in these functions. Unregulated generation companies (GenCos) will produce electricity and sell it at the wholesale level, either through bilateral contracts or through a short-term bulk power market called the Power Exchange. Regulated trans-

94

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mission company (TransCo) will transmit electricity from power plants to local distribution companies (DisCos). These will remain regulated monopolies within their franchise areas. They will be obliged to connect on demand all the customers in their areas and to meter their consumption. At the same time, they will be obliged to provide open access to their grid at nondiscriminatory rates. In effect, the distribution companies will become common carriers of electricity. The DisCos will be responsible for the planning, construction, operation and maintenance of the distribution grid. They will continue to administer the state's efficiency programs. Retail energy companies (RetailCos) will buy electricity at the wholesale level and sell it and related services to retail customers. To ensure nondiscriminatory access, safety, and reliability of the entire system, Vermont proposed that many of the NEPOOL functions be performed by an ISO. A number of major issues that are frequently discussed in the United States arise out of this Vermont proposal. Pricing Issues in the Restructured Environment The Vermont initiative places a requirement to unbundle rates. There is a need to separate the single price that customers pay for energy, transmission, distribution, power quality, and capacity into separate prices and without crosssubsidies among them. Power quality is the assurance that electric power is delivered to the consumer at the required voltage level and is free of voltage fluctuations. The capacity requirement is the assurance that the utility will maintain sufficient reserve generating and other capacity to meet demand during peak periods. The proposed restructured environment mandates that separate prices meet the revenue needs of the GenCos, TransCo, DisCos, and RetailCos. To assure the absence of discriminatory pricing by each type of company, their services and products need to unbundled as well. For example, the DisCos will need to charge for distribution services, metering, and related services, and for access to the system. Among these it will need to raise revenue to cover stranded capacity costs, demand-side management services, renewable energy sources, subsidies to low-income customers, and the cost of state regulation. These charges will be levied from the RetailCos, who in turn will charge final consumers. The RetailCos will charge consumers for the cost of electric energy, for the transmission services provided for by the TransCo, for the variety of DisCos charges, and for the various costs associated with the RetailCos' services. To ensure that customers will receive accurate price signals, Vermont proposed that all costs that are not related to the volume of consumption be levied through a fixed customer-access charge. Accurate price signals will lead to informed consumption decisions. As already mentioned, this charge will cover, among other things, stranded costs, demand-side-management efforts, renewable sources of energy, funding for low-income consumers, and for state regulation. The institution of access charges is intended to prevent "uneconomic

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bypass" of customers seeking alternative energy supply sources, despite the fact that it is inclusion of nonenergy related costs that made the price relatively high, not the cost of the energy itself. Uneconomic bypass is a pathological symptom of bundled rates. The Vermont proposal pays special attention to the economic burden that the proposed actions may place on low-income consumers. The need to subsidize their electricity consumption stands in contrast to the need to provide accurate price signals and without any distortions. To minimize the possible damage of subsidies, it was proposed that low-income consumers will be subsidized from revenues received from the household sectors, so that the commercial and industrial rates will not be affected at all. Furthermore, the subsidy will be provided through the access charges, and thus it will not affect the marginal energy consumption decision of the subsidized customers and of the subsidizing customers. In fact, the Vermont targeted mechanism of subsidizing low-income consumers is similar to the familiar solution of a lump-sum tax favored by many economists. Stranded Costs Stranded costs is one of the most hotly debated transition issues in the United States. These unamortized costs of past investments and related actions are scheduled for recovery through regulated rates and are unlikely to be recovered should restructuring be implemented. Four types of stranded costs are related to past decisions and need to be honored under changed circumstances. The most common type of stranded costs arises as a result of improved efficiency that causes past investments in capacity to become uneconomical soon after installation and long before they have been depreciated. The problem stems from the fact that the benefactors of the efficiency improvements are not the individuals and organizations damaged by the obsolescence of past investments. Thus, for example, a relatively new lOU-owned, base-load power plant that produces electrical energy at $.05 per kwh will not be competitive with a new plant owned by a competitor GenCo, and producing the same output at $.045 per kwh. Since the IOU's plant will discontinue operations prior to full depreciation, past investment in it will constitute stranded cost. Three other types of stranded costs are due to the existence of above-market costs. They are the result of various decisions made under conditions of the regulatory compact, the changing economic environment, and other conditions. Prolonged recession left utilities with surplus generating capacity. PURPA and later legislative and regulatory directives created obligations to act and a burden to pay. Among others, these include past decisions to invest in demand-side management (DSM) programs and in various technologies, including installation and later, decommissioning of nuclear power at certain times and renewables at other times. Among other things, stranded costs include decommissioning expenses for nuclear power plants that utilities are mandated to

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collect. Also, they are mandated to continue paying for contracted for purchased power from generators inside and outside the IOU's service area. Such is the case for many IOUs on the eastern coast of the United States that contracted long-term purchase agreements with Quebec-Hydro. They are also required to continue to purchase power from a variety of PURPA-mandated, qualified producers. It is important to stress that stranded costs are not an issue in competitive markets. They are part of the normal risks of doing business and are fully accounted for in the context of investment decisions. The return on investments used to make those decisions reflects fully the possible risks. Stranded costs are a transition problem in a context of the regulatory compact that has limited the investors' risks and return. Changing the regulatory compact by restructuring has the potential of unbalancing the relation between risk and return. The regulatory compact bound together regulators and IOUs equity and debt holders. Stocks and bonds were purchased under the assumption of economic stability in the industry. Their prices and expected returns reflected this assumption. Equity considerations are often quoted as a justification for preventing stockholders and bondholders from bearing significant losses as a result of a change in the law. The same argument holds in the case of munies, which are owned by the local taxpayers, and in the case of coops, which are owned by their customers. These are arguments for full recovery of stranded costs. But, should all stranded costs be recovered? Should stranded costs that are the result of faulty decisions on the part of an IOU's management be traded equally with those that result from changing the regulatory compact? What is their scope? Most agree that recovery should be granted only in the case of prudently incurred stranded costs. Investments made after an announcement of upcoming competition should not qualify for recovery. A strong argument for full recovery of stranded costs is related to the uncertainty that disallowing full recovery would introduce into the system. A credible government is a prerequisite to a well-operating economy. To encourage long-term investments, there is a need to reduce uncertainty to the minimum possible. As uncertainty grows, so does the need to allocate resources to ensure that the return to future investors fully reflects this additional uncertainty. The Vermont proposal views this as an inefficient use of resources. There is no single credible estimate of the extent of stranded costs that may need to be recovered as a result of restructuring in the United States. Some have estimated them at U.S. $135 billion. This sum represents more than half of the total equity value of all the IOUs.10 Discussions at the Harvard Electricity Policy Group have placed these costs at more than U.S. $200 billion. There are several different methods to estimate and to recover stranded costs. Two alternate methods for determining them administratively have been suggested. The "bottom-up" approach is similar in structure to a cost-of-service study that seeks to assign the stranded costs to a particular customer and to a particular consumption action. The "lost-revenues" approach, on the other hand,

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seeks to estimate the difference in revenues that results as a result of the changed regulatory compact. Two problems arise. The lost revenues approach is not capable of assigning the stranded costs to individual consumers. More important, to the extent that it is based on ex ante data, it requires forecasts of costs and market prices for some forecasting time horizon. To the extent that it is based on ex post data, the estimates are accurate, but not timely. During the year the absence of stranded-cost recovery may hinder fair competition. An alternative method to assess stranded capacity costs is to place all the stranded assets, both generating capacity and contracts, for sale through an auction. While theoretically it is straightforward and indeed a more accurate reflection of the true value of the assets, opponents have raised several practical issues. Under some circumstances, an auction mechanism may lead to undervaluation of the stranded assets, and thus the mechanism will not provide full-value reimbursement to asset holders. Such a result may occur in response to untimely scheduling of the sell-off of many assets. The influx of large supply of assets at once may force their market price down. Secondly, uncertainty over future organization and functioning of the relevant markets is likely to increase uncertainty and reduce the bids for the assets. Alternatively, it is possible that such uncertainty will lead the new owners of the assets to overprice their services in response to this uncertainty. The result would be that customers will be forced to pay higher rates than would be expected with lesser uncertainty. Another problem arises from various limitations on the very conduct of transactions in stranded assets. The source of such limitations may stem from the contractual obligations in bond indenture provisions or power purchase contracts. Similarly, there may exist restrictions on trade in nuclear assets that are related to safety provisions or related to the identity of the purchaser. Finally, trade restrictions may stem from concern over the resulting concentrated market power of generators, or other asset holders. Indeed, untoward market power is a central issue in the design of electricity markets. Oligopolistic arrangements are considered poor replacements of monopolists. The Vermont proposal includes a combination of an administrative and market-based treatment of stranded costs. Generating capacity and power purchase contracts are to be auctioned. To prevent undue concentration of market power, the proposal includes a provision that no entity should be able to acquire generating assets above a predetermined maximum percentage of the region's generation capacity. To correct for the possible lack of information and to prevent excessively low bids, Vermont proposed a package of basic plant and/or contract information to be compiled by independent auditors and to be made public. Deferred DSM expenditures and other "regulatory assets," such as provisions for low-income consumers will be disposed of through the access charges of the DisCos. No clear-cut proposal has been suggested for dealing with the decommissioning of nuclear power. A very interesting mechanism intended to reduce uncertainty even further is included in the Vermont proposal. Its intention is to protect Vermont con-

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sumers from being affected adversely as circumstances change in the future. This may occur, for example, should we witness a return to conditions that existed in the 1970s. The Vermont proposals include an insurance policy to be issued to the DisCos so that it will be able to reward local customers through the customer charge, should the market value of the stranded assets rise significantly above the sale value. The potential insurer will pay the DisCo an amount equal to the difference in the actual price of electricity that originated from an auctioned asset and the implicit price of electricity that determined the auction price of the asset. The insurance payments to the DisCos will offset at least partly the access charges to be paid by consumers. Here also are many practical issues to be sorted out, among them, the price of the insurance and the duration of the policy. More important, the nature of the trigger mechanism needs to be selected. Should it be the market price of electricity or an index that reflects the market value of the generation capacity sold. The time frame during which the stranded costs are to be recovered is an issue as well. As the recovery period is reduced, so the access charge will increase. Conservation, Demand-Side Management, and Environmental Issues The proposers of the Vermont restructuring plan are proud of past, regulator inspired and mandated achievements in what is commonly called "social benefits." These benefits include conservation and other demand-side management programs, ensuring environmental protection and universal access to electric energy at a reasonable price and the provision of a social "safety net" for low-income electricity consumers. Originally mandated by PURPA, conservation and DSM programs were intended to reduce the need to install new capacity and to reduce the reliance on imports of energy from OPEC countries. Some states extended the objectives of such programs to the protection of the environment. Under the regulatory compact, the actions implicit in these programs were contradictory to the main objective of IOUs to generate and sell electric energy. To create incentives sufficient to make IOUs eschew their impulse to expand production, all the DSM and conservation programs include provisions to pay IOUs for not producing. In addition, the early programs coopted the IOUs to become the financiers of investments made by consumers of electricity at the premises of the consumers that were intended to reduce the need to consume electricity. These actions were justified by the existence of market barriers to economic DSM investments. Among the barriers are a lack of customers' access to capital and existing commercial landlord-tenant relationships that fragment benefits of such investments.11 The Vermont proposal places the responsibility for all such programs in the hands of the DisCos. In this, the DisCo will replace the IOU. It will be responsible for providing the investments and for collecting the funds needed to support these

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investments. As the IOU was in the past, it will be subject to oversight and to regulation by the regulatory commission. While the proposers of the Vermont initiative are explicitly unsure of the incentives that the new industrial organization will create for continuing these programs, they term the proposed conservation and DSM mechanisms as temporary. Presumably, the transition period will end as the market barriers that gave rise to its institution will be removed. DSM and related programs are viewed by Vermont as an integral part of planning the distribution system. The DisCo is charged with providing distribution capacity in the most cost-effective way. The wires business is subject to two conflicting trends. On the one hand, it is subject to increasing costs due to environmental concerns. On the other hand, it continues to enjoy economies of scale. The planning process of the distribution system will address issues of resource choice and control, timing, and environmental degradation. The Vermont proposal seeks a fundamental change in the motivations that will drive the actions of the distribution system operators. Unlike the traditional IOU, the DisCo will plan its system from the perspective of the final consumer, not the generating plant. It will study its market, evaluate the needs of its consumers, and provide the most valuable combinations of various elements of a modern distribution system. It will include energy efficiency programs, power quality measures, back-up power, and voltage stability and reliability mechanisms. With all these, will come the reduction of the need for new distribution lines. The Vermont proposal is equally proud of the state's environmental programs. To promote improvements in environmental quality, the proposal seeks to accelerate implementation of U.S. Clean Air Act and performance standards for all existing generators. In addition, the DisCo will be mandated to promote ultraclean technologies by the commercialization of clean technologies, such as fuel cells and renewables. The DisCo will finance these activities also through its access charge. Here also the DisCo will act as financier. To insure efficiency, the actual actions will be performed by third party for profit companies. Finally, to ensure that low income state residents benefit from the proposed competitive structure, Vermont proposals continue the lifeline programs that have been so common throughout the United States. Residential customers whose income is less than 125 percent of the poverty level will receive winter season discounts of between 20 and 40 percent. The program will be funded through a surcharge levied through the DisCos' access charge. In this fashion, the marginal prices to all consumers will provide precise price signals and will not affect consumption decisions. UNRESOLVED TRANSITION ISSUES Proposed changes, such as those in Vermont, have spawned an intense public debate that highlights an evolving struggle over the future sharing arrangements of a variety of potential risks and benefits that are a natural by-product

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of the proposed restructuring. The regulatory compact existed for over a hundred years. The relative shares of risks and benefits, even if unfairly distributed, were understood and accepted by all. Even those players who clearly stand to benefit from the new rules of the game are positioning themselves so as to increase their share of the future pie. The Basic Service Package Under the historic regulatory compact, electricity consumers were assured that electric energy will be available under all circumstances, and that there exists an oversight concerning the threat of disconnections, such as might result due to disputes over nonpayment of electric bills. The responsibility for assuring future supply has been a flag under which utilities throughout the world have rallied in their opposition to restructuring. The opposition to proposals, such as that in Vermont, has claimed that vertically integrated systems are the only means to assure that sufficient capacity will be available in the future. Traditional utilities claim that electricity, unlike regular consumer products, cannot be provided with any assurance by an unbundled system. To this day, the performance of the U.K. system is deemed too new to serve as an appropriate example. To assure consumers and voters, the Vermont proposal includes a basic service package. It consists of several components. The consumer will be protected by a combination of regulated rates, market-determined prices, and an insurance policy. System access and delivery charges will pass through the regulated DisCo costs, short-term, spot-market, electric energy costs as published by the Power Exchange, and regulated, fixed, cost-based TransCo charges, as well as associated administrative and general expenses. In addition, insurance arrangements will prevent unexpected price increases. Furthermore, to protect the consumers from bill fluctuations, they will be provided with budget billing. Above all, consumers will have a choice of a RetailCo by giving an agreed on notice. Independent System Operators (ISOs) There is almost no proposal for reforms at the federal or state level that does not address the possible problems that may arise as a result of an unfair playmaker. The Federal Energy Regulatory Commission has spelled out the issues and the requirements in FERC Order 888. It calls for the creation of an independent and separate entity that will be unaffiliated with any IOU and will take over the operating control of electric transmission facilities and assure equal access to all. The Vermont proposal suggests several steps that are required in order to transform NEPOOL into an ISO. The current operation of the NEPOOL lends itself to being an ISO. Today, the operating arm of NEPOOL, the New England Power Exchange (NEPEX), maintains the physical reliability of the rel-

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evant control area, and it monitors and enforces compliance by members of the area rules. These are central functions of the ISO. To make the ISO independent, FERC suggested that • The ISO's governance structure must reflect fairness and nondiscrimination. • The ISO and its employees should be disallowed financial interests in the economic performance of any of the market participants. • Open access should be assured by unbundled, grid-wide tariffs that are applicable to all users. • The primary mission of the ISO will be short-term reliability of grid operation, by reference to standards set by the North American Electric Reliability Council and the relevant regional reliability organization. • To promote efficient trading, the ISO will be empowered to take operational actions to relieve any constraints on the system that it may discover. • The ISO should be endowed with a variety of incentives and tools to operate efficiently. • The ISO should conduct studies to identify operational problems and need for system expansion. It should provide transmission price signals so as to encourage efficient use and investments in generation, transmission, and related activities. • Transmission system information should be made public and on a timely basis. • The ISO should coordinate its activities with neighboring systems. • The ISO should establish a system for resolving disputes among the participants in the market. Pacific Gas and Electric (PG&E), in its filing before the FERC on this issue, suggested that in order to assure the independence of the ISO it should be constituted as a not-for-profit, public benefit corporation. The Vermont proposal has identified another specific change that is requisite to achieve the FERC-mandated conditions. NEPOOL dispatches electric energy on the basis of incremental generating costs. To achieve economic efficiency through a market mechanism, the dispatching must rely on marketdetermined prices (i.e., the prices bid by suppliers). This will provide the proper incentives for numerous unregulated generation suppliers to sell their power through the NEPOOL. In addition, however, a bid-price system must be set up so as to create an incentive to run those generating units needed to maintain the transmission system's integrity. Similarly, NEPOOL will have to set up an accounting system for those loads that are used to provide reserve margins and reliability. Finally, an appropriate accounting system must reflect accurately all these price-driven cost responsibilities. Public Attitudes toward Restructuring Initiatives While Vermont is an interesting platform on which to explore restructuring issues, it is not an unique example. Also, it is not without many critics. While narrow interests are the source of most criticisms, the opposing views do raise

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legitimate public interest issues that have not received adequate treatment. Several restructuring evaluation criteria are typically listed. Among the desirable characteristic of a restructured system are the following: • • • • • • •

All classes of consumers should be treated equitably. Stranded costs should be borne by those who choose to leave their current supplier. All energy suppliers, not just utilities, should be subject to uniform standards. All consumers should have access to electric service. Safety and reliability must not be jeopardized. Exclusive delivery service areas should be maintained. Requirements contracts should not jeopardize financial security.

While all these issues are typically addressed by restructuring proposals, there are disagreements as to the performance of the proposals. Thus, for example, electric cooperatives who serve residential consumers are opposed to proposals that may result in inequitable, but not unequal, burden on different classes of consumers. In their opinion, the greater freedom of choice that restructuring proposals offer to consumers will result in threats of bypass decisions by large consumers. Such threats may lead to uneconomic results and to greater burden on small customers, who will have to bear the fixed costs of maintaining the system. From the perspective of small, rural customers, the bill reductions that retail-wheeling may bring about is marginal. Some 70 percent of the typical rural electric bill is accounted for by wholesale energy costs. Wholesale competition, therefore, is a welcome mechanism to reduce prices. In their view, retail-wheeling introduces major risks and small potential benefits. Surprisingly, large industrial energy consumers are equally critical. Their criticism is motivated by a different set of forecasts concerning the repercussions of the various initiatives. While FERC estimated that Order 888 will result in a reduction of the cost of electricity to consumers by between $3.8 and $5.4 billion, the Electricity Consumers Resource Council (ELCON)12 expressed a concern for the stranded costs that will be borne by consumers only. The 100-percent rule will be a barrier to competition. Indeed, ELCON views Order 888 as an anticompetitive step. The presence of uneconomic assets is not always the result of prudent behavior. There is no reason to impose exit fees on individuals and organizations who decide to seek alternate sources. Furthermore, the imposition of imprudent-costs pass-through will encourage imprudent investment behavior in the future. ELCON claims that FERC's insistence that only prudently incurred costs will be passed on to consumers is an empty intention. An impressive discussion of the various views took place in Minnesota during an ongoing debate in the legislature concerning restructuring options. The discussion focused on the advantages and disadvantages of five basic alternate plans:

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1. Do nothing. 2. Establish guiding principles for the state's energy system. 3. Encourage wholesale competition through a voluntary power pool. 4. Encourage wholesale competition through a mandatory power pool. 5. Authorize retail-wheeling through direct access.

The passive approach of doing nothing is preferred by those who consider the various proposals as unripe and in need of experimental dry runs, especially in other states. Waiting will allow FERC to refine its proposals, while regional policies evolve uniquely in each region. It will allow regulatory agencies time to plan while developing the expertise needed to operate within the new economic reality. Indeed, the experience of other states who are running ahead of the pack will be a useful backdrop for Minnesota. Waiting, however, is not without its cost. Should other states move ahead and experience economic benefits, Minnesota may experience losses due to the outmigration of economic activities. The same benefits and costs are likely should Minnesota choose the second option, to establish state guidelines. This is an almost do-nothing-and-wait alternative. Discussions will take place, and guidelines will be structured at the legislative level. The actual implementation steps will be taken, or not taken, by regulatory agencies and utilities. The only additional implication of this alternative is that knowledge will be gained through the public debate that will ensue. The third option consists of legislative encouragement of voluntary wholesale competition. This option may create all the benefits that wholesale competition is supposed to yield, without disrupting unduly the existing structure of the electric system. It will be consistent with federal initiatives, current state-integrated resource planning, and demand-side management. At the same time, such actions will increase reporting requirements and create a need to work out jurisdictional issues. In other words, the creation of new institutions is not without costs associated with their design and implementation. The fourth option is similar to the initiative that was adopted by California and is being debated in Vermont. It includes a mandatory state-wide pool and an electricity "stock-exchange." All generating facilities will be placed under the control of an ISO, who will be provided with bids of supply. Many implementation options are raised by this proposal. Some, or all, customers may be allowed to buy from the pool. It may lead to prolonged and costly litigation over the state's jurisdiction and over ownership and pricing of assets. Indeed, mandatory competition may not maximize possible benefits. A self-organizing system that evolves slowly over a long period of time may be preferred. The fifth alternative consists of at least partial retail competition. Rivalry for customers has the potential to reduce prices. Certainly it maximizes customers' choices. However, should competition evolve in an unexpected manner, it could lead to reduced regulation, increased monopolistic control, and increased

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electricity prices. It could increase stranded costs due to innovation and affect adversely reliability, power quality, and transmission system reliability. A similar set of issues was recently raised by NARUC and others.13 It is not clear who should lead the restructuring revolution within the complex U.S. system. Questions remain as to the means to evaluate alternate initiatives. How long will it take to observe fundamental changes in the system? Some suggest that dynamic, rather than static, measurements are needed as a basis for making decisions. How should the benefits and costs of the restructuring be shared among the various participants? Restructuring that affects economic benefits and costs, as well as long-standing property rights has become an issue in the United States more than in any other country that has considered or implemented changes. While FERC and Congress are pushing forward promoting increasing competition, state organizations, such as the National Governors' Association (NGA) and NARUC, are struggling to ensure that their authority in steering electricity systems is preserved.14 PROTECTION AGAINST EXCESSIVE MARKET POWER Under the old regulatory compact, IOUs were granted market power; indeed, they were protected from all competition, in return for the right to public oversight. The various proposals and actions replaced the old compact with a variety of competitive arrangements. Competition replaces oversight as a mechanism for protecting consumers. Public debate focuses frequently on the possibility that competition may lead some players to acquire excessive market power. It may endow some players to influence market prices and subdue rivals. Should some players gain undue market power under the new circumstance, it will lead to results that are contrary to the intended reforms. There are a variety of circumstances that can lead to excessive market power. A dominant firm, or a small group of firms, can control production and market prices. Alternatively, barriers to entry can prevent potential competitors from offering their products and services. Such conditions can result from even a limited influence of a single firm on market-clearing prices in the spot market at a certain limited number of times. This is particularly problematic in regions such as New England, where two-thirds of all generating capacity is owned by three utilities. To prevent these unwanted conditions, it is necessary to create protection mechanisms. It is doubtful that current antitrust laws constitute sufficient protection. Since the rules of the competitive game are so different in the different states, it is important to fashion both incentive and market-power control mechanisms that will be suited to the emerging patterns of behavior that can be expected in each state. Some observers call for a uniform set of rules for all the states. Though no one has pointed it out, this is equivalent to a national electricity policy with slight state variations. This, in fact, is the European Union approach. Others stress the uniqueness of each state's electricity and

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legal system and the consequent need for a locally optimized system of checks and balances. Notwithstanding electricity issues, this debate follows a classic pattern of states-rights debates.

NOTES 1. The Western Area Power Administration (WAPA) operates in California, Arizona, Utah, New Mexico, North and South Dakota, Colorado, and parts of Nebraska, Nevada, Wyoming, Minnesota, Iowa, Montana, Texas, and Kansas. The Alaska Power Administration (APA) operates in Alaska. The Southwestern Power Administration (SWPA) operates in Arkansas, Louisiana, Oklahoma, and eastern Texas. The Southeastern Power Administration (SEPA) is responsible for Alabama, Florida, Georgia, Kentucky, Mississippi, North and South Carolina, Tennessee, Virginia, and West Virginia. The BPA is responsible for Idaho, Oregon, Washington, and parts of Montana. 2. It is important to remember that, in the pre-PURPA days, efficiency did not constitute a basis for rate making. 3. A striking feature of the business climate in private electric companies in the United States prior to the last decade was apparent to any casual visitor at management offices. The average near-retirement age and professional training in engineering were the dominant characteristics of all senior staff. The long decades of the regulatory compact created business conservatism that could be changed by replacing the entire management only. This has indeed occurred in the last decade. 4. This was apparent in the formal hearings that each state regulatory commission carried out as part of the PURPA implementation process. Rate decisions were challenged in courts and reached the U.S. Supreme Court that in API v. AEP affirmed the Federal Energy Regulatory Commission's use of full avoided costs as a basis for rate making. A research arm of the state regulatory commissions was established, the National Regulatory Research Institute (NRRI), and was commissioned to assist in the implementation process (see, for example, Profozich, Czamanski, McElroy, Biggs, Pryor, Russell and Associates 1981). 5. FERC's thinking on this matter is stated clearly in "Notice of Proposed Rulemaking," Docket no. RM947001. 6. See "Inquiry Concerning the Commission's Pricing Policies for Transmission Services Provided by Public Utilities under the Federal Power Act," FERC Docket no. RM93-19-000, 26 October 1994, and "Policy Statement Regarding Regional Transmission Groups," 1993. 7. See "Inquiry Concerning Alternative Power Pooling Institutions under Federal Power Act," FERC Docket no. RM94-20-000, 26 October 1994. 8. The study involves 150 experts who interact under a variety of rules that constitute alternate institutions. The bids are submitted through the Internet. 9. Vermont's planning suggests that there is a great deal of concern that imposed competitive solutions will not be suitable, and that in the absence of its own solution, the state will not be able to prevent adoption of the "wrong" system. This is suggested by the tight schedule that is being proposed: legislation in 1997 and implementation in 1998. 10. The Economic Report of the President, 1996. 11. According to the U.S. Energy Information Administration, U.S. utilities spent some $12 billion on DSM between the years of 1991 and 1995. This resulted in a

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reduction of peak demand of about 29,500 MW in 1995, or about 4 percent of the summer peak. It resulted in an electric energy saving of 216,000 Gwh during the period of 1991 to 1995 and of 57,000 Gwh in 1995 alone. This saving constituted almost 2 percent of total U.S. electricity sales in 1995. 12. Written testimony of John Anderson of ELCON presented before the Senate Committee on FERC Order 888, 11 July 1996. 13. See NARUC guidebook to regulators on restructuring (1996). 14. The 1997 Las Vegas meeting of the NGA has adopted guiding principles for restructuring. Among other decisions, the NGA called for grandfathering state actions in any Congressional legislative action.

7 The World Beyond

On the eve of the third millennium, the world's electric industry is in flux. There is little doubt that the vast majority of observers of the electricity industry would agree with this terse yet accurate characterization of its status. Certainly, this characterization comes to mind when comparing the last years of this century to the history of the industry heretofore. Some countries are taking very quick and bold steps to change the status quo. Companies are broken up and often privatized. New institutions are created. The U.K. pioneering restructuring effort has been pretty much completed. At the same time, some countries, such as the United States, are in the midst of considering a variety of alternate initiatives. No clear national policy has emerged. The proposals considered by the various states are truly heterogeneous. And while some states have adopted a wait-and-see posture, others are taking practical steps forward and are leading toward a U.K. type of reform. There are few who doubt that the old U.S. regulatory compact will be replaced by competition throughout the United States. The rest of the world is marching behind the two forerunners, the United Kingdom and the United States. Some countries have already taken definite steps. Most countries are conducting initial discussions concerning the steps that will be taken. Israel's efforts constitute a telling example of the way that private and public interests play themselves out, clearly leading to a variety of

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excuses to do nothing and merely maintain the current state of affairs.There are many countries that are not yet participating in the reform movement. But, many countries, especially in Europe, will not be able to withstand the tide of reforms because of actions taken by their neighbors. The influence of neighboring systems may be felt because of existing interconnections and trade agreements or, as in Europe, because of general economic agreements, of which the electric industry is just a particular detail.

THE EUROPEAN ELECTRICITY MARKET In recent years, the European Union (EU) has taken major steps to create a single economic market. To this end, trade barriers have been removed, and sectors that were protected in the past are being opened up to competition. While the electricity industry in Europe remains organized according to national borders, in 1992 the European Commission proposed to introduce, albeit gradually, competition and customer choice.1 The initiative would have created retail level competition through third-party access by allowing a limited number of distributors and customers to negotiate access to the network and to choose their supplier. Major disagreements emerged among the EU members. Some members of the EU initiated steps to liberalize their systems. Countries like the United Kingdom, Sweden, Finland, the Netherlands, Austria, Italy, and Portugal began implementing privatization of SOEs, restructuring organizations and institutions, allowing independent generation, and replacing monopolies with competition. These actions were motivated by pressure from industrial customers seeking cheaper electricity and by a growing need for capital to finance new capacity. The opposition came from the electric monopolies and old style managements defending the status quo. EDF, the powerful stateowned French company, stood at the forefront of the opposition. A compromise agreement, the Directive, was reached only in June 1996. According to the new initiative, competition is much more limited, and its introduction is gradual. The Directive that spells out the agreed-upon proposal includes major elements of the French proposals of 1994 that consisted of a "single buyer model." The French proposal permitted limited competition in electricity generation in the form of competitive tendering for new capacity. However, a single buyer of electric energy would retain monopoly rights to sell electricity to customers. In effect, the French proposed limited wholesale competition and precluded retail-wheeling. While Germany and the United Kingdom advocated unbundling of vertically integrated utilities, some elements of the single buyer concept were introduced into the Directive. The final agreement came in 1996 and provided for limited market opening of about 22 percent of the EU market (see Table 7.1). Areas that consume in excess of 100 Gwh were empowered to choose their suppliers immediately. For consumption areas, with annual consumption that exceeded 40 Gwh, or 8

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The World Beyond Table 7.1 Electricity Consumption, 1996, and Liberalized Share in EU Countries Member State

Final Consumption (Toe)

Share to be Liberalized (GWh)

Austria

4,013

46.66

Denmark

2,686

31.23

Finland

5,615

65.29

Germany

38,912

452.5

Ireland

7,144

14.83

Luxembourg

5,924

5.00

Netherlands

7,144

83.07

Portugal

2,439

28.36

Sweden

10,704

124.46

United Kingdom

25,604

297.72

5,885

68.43

France

29,456

342.50

Greece

2,931

34.08

Italy

20,436

237.62

Spain

12,139

141.15

Belgium

Source: EU, Directorate-General XVII, 20 December 1997: www.EU.org

MW, a minimum level of market opening was set for each member state, based on the average market share across the EU. The Directive includes a provision for a gradual and progressive lowering of the 40 Gwh limit, so that it reaches 20 Gwh by 1 January 2000, and 9 Gwh by 2003. Thus, according to the Commission's estimate, some 30 percent of customers in the EU will be exposed to competition. The Directive is a comprehensive statement that relates to all aspects of the electricity business. It spells out commonalities among EU member states, and yet it leaves it up to the states to work out the practical details as to the means of implementing the Directive. Thus, for example, the Directive leaves it to the states to provide authorization to build, operate, purchase, or sell a generating plant. It requires, however, that the authorizations be granted on the basis of publicly known, transparent criteria that are "objective and nondiscriminatory." The criteria that were to be published by 1 January 1995 can relate and are limited

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Privatization and Restructuring of Electricity Provision

to security and safety of the installation, protection of the environment, land use provisions, and technical and financial capacity of the applicant. Similar provisions were proposed for transmission and distribution lines operators. Refusal to authorize activities must be publicly explained. Universal service is to be assured by the states. Production and transmission companies will operate under a public-service obligation as determined by member states. As an alternative to granting licenses on a competitive basis to applicants on the basis of clear criteria, the states can launch invitations to tender for new production and/or transmission capacity. Member states are obligated to institute a system operator whose responsibility will include operation, maintenance, and development of the transmission system and interconnections. In order to ensure security, reliability, and efficiency of the system, the transmission system must be operated separately from the generation and distribution activities. While consultation with all the parties concerned will be required, the system operator will be independent in deciding to implement technical and operating rules. Similar provisions were included in the Directive for the operation of the distribution system. It is critically significant that the Directive mandated unbundling and transparency of accounts, even in the case of vertically integrated operations. Unbundled accounts will serve as a means to verify the absence of cross-subsidies. Finally, the member states will need to implement conflict resolution procedures as a mechanism to resolve disputes. While the policies in the United States take into account explicitly social concerns, such as environmental degradation and poverty, the EU Directive is almost empty of such concerns. The member states may reorder dispatching priority to take account of renewable energy. If at all, such a provision will constitute an exception rather than the rule, which states clearly that priority dispatching will be on the basis of economic merit. The French opposition to the initiative is understandable in terms of the expected impact of the Directive on the generation business. Electricity generation, transmission, and distribution in France is dominated by EDF. EDF is Europe's largest electricity company and nuclear power producer. Nuclear power accounts for three-quarters of France's electricity generation. In 1996, France produced 488.9 TWh of electric energy, representing an increase of 3.7 percent compared with 1995. The electricity generated by EDF is distributed as follows: nuclear—374.8 TWh, conventional thermal—21.2 TWh, and hydroelectric—61.8 TWh, that is a total of 457.8 TWh. The total domestic consumption amounted to 383 TWh, a 4.1 % increase as compared with 1995. While a French government commission recently made some recommendations which would have lessened the dominant role of EDF, there appears to be little chance of any far-reaching reform. As elsewhere, the French system was built to take advantage of economies of scale. The resulting large and expensive plants took ten years and more to construct. In the almost risk-free environment, customers bore the risk of wrong decisions. The planners' deci-

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sions were based on planning horizons of forty years and extremely low discount rates. A salient feature of this decision-making environment was frequent mistakes. The rapid introduction of combined-cycle gas turbines following liberalization constitutes a major threat to traditional decision makers. Combinedcycle gas turbines grew up to 20 percent of capacity during the 1990s. The predominance of nuclear power and the resulting threat of stranded costs looms large over any attempt to introduce competition in France. Paradoxically, although privatization of EDF seems unlikely, EDF has become a major investor in several independent power projects abroad. EDF has recent power project investments in Hungary, Spain, the Ivory Coast, Argentina, Portugal, Italy, Poland, and Sweden. France is not the only European country with a large portion of its installed capacity in the form of large nuclear and coal-fired plants. In Spain, nuclear power accounted for 17 percent of installed capacity and 35 percent of energy production in 1994. Coal accounted for 25 percent of installed capacity and 38 percent of energy production. Like many countries, Spain is not well endowed with energy resources and consequently its electricity policies are influenced by its effort toward energy self-sufficiency. While natural gas from Algeria, across the Mediterranean, will play an increasing role in the future, today coal and nuclear power dominate the electricity industry. In addition, Spain has an interest in becoming well integrated in the industrial economy of Europe. These concerns have created an unusual structure and unusual policies for the Spanish electricity industry. The reforms in Spain began relatively early. In the mid-1980s, the national, government-owned grid, Red Electrica de Espana (REE) was formed from the assets of all firms in the country. REE is the national central dispatcher. The generation plant is a mixture of government-owned and private assets. The largest company, of which 68 percent is government owned, controls some 50 percent of the installed generating capacity and some 40 percent of distribution. Since 1987, prices were set up in Spain in a price-cap framework. The Ministry of Energy published tariffs to be paid by end users based on standard costs. These costs are adjusted periodically to reflect changing fuel prices and interest rates. Government's interest in expanded capacity and/or environmental improvements gave rise to increased costs that accrue through increased rates to the industry. Producers have an incentive to reduce costs so as to generate increased profits. Between 1988 and 1994, real electricity prices have declined by 1.1 percent per year on average. At the same time, technical and financial performance of producers has improved as well. Spanish decision makers have been quite content with the performance of the electricity system under the price-cap method that has been operative since the late 1980s. It enabled improved technical efficiency, declining prices, and stability in the electric industry's fuel mix, a peculiarly Spanish interest motivated by concern for self-sufficiency. Spanish policy makers had an interest in

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Privatization and Restructuring of Electricity

Provision

marginal improvements without changing the overall status quo. Three objectives guided the new electricity legislation of 1994, the Ley de Ordenacion del Sistema Electrico Nacional (LOSEN): • The creation of a transparent regulatory system through a regulatory commisson. • Improvement in technical efficiency by competitive bidding for new capacity. • Improvements in allocative efficiency by enabling limited "bypass" by independent producers. Despite the creation of a bypass mechanism, the Spanish legislators envisaged limited competitive pressures and thus saw in the new regulatory commission the main source of discipline. The five-person commission includes politically appointed buraucrats and academics who will serve for a five-year term. The legislation does not spell out the details of the regulatory practice. The nature of the relationships among regulators and regulated will be defined through interaction in the years to come. It is important and extremely significant that the new legislation has endowed the regulators with impressive powers to introduce competitive bidding for new capacity. The regulators will determine bid evaluation criteria and will select the winners. This is a significant regulatory intervention, much beyond the power purchase contracts in the most progressive states in the United States. It is not clear whether this will require planning activity by the regulatory body and what will be the nature of capital market response to this institutional change. Similarly uncertain is the future of the bypass provision in the legislation. Theoretically, these provisions represent a direct-access policy. Its workability depends on the rules of the game and on the incentives that potential participants may have to actually engage in the process. Here also, the legislation delegates to the regulators the management of the interactions among sellers and buyers. The regulators will have to sort out two pricing issues to make a bypass a reality. It will have to establish estimates of the national transmission system's opportunity cost and establish stranded costs policies. These depend crucially on the future operating procedures of the grid and on various constraints concerning national coal usage policies and associated price-support policies. Industrial users are the most likely candidates to engage in bypass activities. Today's industrial electricity tariffs provide no incentives for such activities. The Spanish approach to restructuring has created a powerful regulatory mechanism capable of establishing ground rules for promoting technical and allocative efficiency improvements. It has failed to establish commensurate incentives that will prompt the players to participate in the reforms. Above all, there is a need to change the intertwined ownership structure. Such a step will clarify interests, a neccessary step toward improved efficiency.

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COMPETITION WITHIN THE PUBLIC SECTORNORWAY AND ITS NEIGHBORS The Norwegian electricity supply system constitutes a unique and extremely interesting example of creating institutions that deal with the twin problems of incentives for efficient allocation of resources and public sector ownership of facilities. Norway's approach suggests that under some circumstances, competition and public ownership are indeed reconcilable. The institutions that Norway fashioned are a stark counterintuitive example to the prevalent ideas that competition goes hand in hand with private and diffuse ownership. Because of its climate, industrial structure, and inexpensive electric energy, Norway has the highest per capita consumption of electricity in the world, about 25,000 kwh per annum. Also, Norway is one of the few countries in the world that supplies the vast majority of its electricity consumption needs by means of hydroelectric power. This is in contrast to the rest of the world, where only about 6 percent of consumption is provided for by hydroelectric power. While hydroelectric power stations do not pollute the environment, power development projects do damage the environment due to the large reservoirs that need to be constructed and the changed water circulation that they cause. For the most part, hydroelectric sites are located far away from population centers, and thus, their utilization requires a massive transmission grid that affects the environment as well. The evolution of Norway's electric industry was influenced greatly by the tremendous increase in electricity consumption, which outstripped severalfold the population growth. Since 1945, electricity consumption grew by 800 percent, while population grew only by 50 percent. Since 1980, investments in electric capacity are continuing, albeit at a reduced rate. In constant dollars, investment in 1992 was about one-third of the investment in 1980. The hydropower industry in Norway employs almost 20,000 people and contributes about 4 percent to the GNP. Electricity is produced by some 845 power stations with an installed capacity of 27,000 MW. The largest station, Kvilldal, has a maximum production capacity of 1,240 MW, or some 4 percent of total Norwegian capacity. Historically, demand was met by the construction of hydroelectric power stations owned by the local municipal and regional councils. The thirty-four largest production companies account for some 96 percent of total production. While hydro power is deemed an important contributor to Norway's wellbeing, water resources in Norway are subject to legislation that dates back to provincial laws from the twelfth century. The very early laws established private rights of ownership, while restricting usage and the type of changes that can be made, so as not to affect fisheries. Legislation pertinent to hydro power evolved over the centuries. The Watercourse Regulation and the Industrial Concession Acts of 1912 restricted foreign wholesale purchase of waterfalls.

114

Privatization and Restructuring of Electricity Provision

These acts laid the foundation for the requirements to obtain licenses to exploit hydro power. The transmission and distribution grid that delivered electricity to the households within the region was owned by the same entities that produced the electricity. Over time, interconnections evolved among the local systems and with neighboring countries. While water supply was accumulated mostly in the spring, Norway is a winter-peaking system, requiring back-up power from neighboring, nonhydroelectric systems. The 1990 Energy Act created in Norway a market-oriented competitive system that may be viewed as the most comprehensive in the world. This is despite the prevalence of public-sector ownership. The new regulations came into effect in 1991. It created competition in the generation and sale of electricity throughout the country. The main motivation for the changes that were implemented was to reduce the local monopoly power and to increase efficiency of the system, while eliminating the great variance in electricity prices. It was an explicit decision in Norway that improved efficiency in the electricity sector can be achieved through the implementation of a pricing scheme that would reflect accurately the total cost imposed by consumption. The continued public sector ownership of the country's natural resources was deemed as a constraint in the restructuring effort. Despite the dominance of the public sector in the electric industry in Norway, the system is populated by a variety of enterprises. There are several types of power utilities. This term refers to production utilities, vertically integrated utilities, distribution utilities, wholesale utilities, and industrial companies. All power utilities must hold a trading license. Such a license provides governmental authorities with the right to inspect grid operations and pricing. According to the license, power utilities must keep separate accounts of grid operations and other operations that are exposed to competition. The monopoly prices are regulated by the Norwegian Water Resources and Energy Administration. The price of electric transmission services may not exceed recognized costs, including a reasonable return on investment. In addition, utilities must obtain construction and operating licenses that ensure uniformity throughout the system. The various utilities transmit electricity through a grid owned jointly by Statnett, the state-owned Norwegian Power Grid Company (80%), and by counties, municipalities, and private companies (20%). There are 129 production utilities in Norway. These are limited to electricity generation. They do not own any of the transmission and distribution network. The largest producer is the state-owned Norwegian Energy Corporation, Statkraft, with average annual output of almost 32,000 Gwh, or almost 30 percent, and an installed capacity of 28.4 MW. The other utilities are owned by municipalities and are relatively small. Some 15 percent of capacity is owned by fifty-seven private corporations. Many of these produce electricity for their own use only.

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Twenty-three wholesale utilities are owners of generating plants and of parts of regional grids. They are owned jointly by several municipalities and by power utilities. Their original purpose was to purchase electric energy for resale to the 101 local distribution utilities who own local distribution grids. While in the past distribution utilities were restricted to the sale of electricity within their geographic monopoly areas, today they trade throughout the market. While they can buy electricity in the spot market, in fact most of their sales originate in electricity purchased from local wholesale utilities. In addition, there are ninety-eight vertically integrated utilities, each of which is in fact both a production and a distribution utility. Finally, there are twenty-one trading companies and several power brokers. Trading companies resell electricity bought in the open market throughout the country. Power brokers are trade facilitators. They do not buy or sell electricity. For a fee, they negotiate contracts between buyers and sellers. The Energy Act created rules for controlling the monopolistic elements of the system, while encouraging competitive interaction. Thus, while consumers are obligated to buy grid services from their local power utility, they are free to purchase electric energy from any generator, wholesaler, or trader, while obtaining information and contracting help from a broker. The monopoly power of the grid owners are circumscribed by price and quality regulations. The Norwegian Water Resources and Energy Administration is the regulator who monitors grid operations and sets tariffs. In 1993, Norway adopted a system of point tariffs as a mechanism to institute a national electricity market. Point tariffs are paid by consumers at the point of consumption and by generators at the point at which they feed electricity into the grid. The tariff paid by consumers covers both transmission and distribution costs, and thus it differs among Norway's regions and according to the level at which electricity is consumed. The tariff paid by generators includes a fixed component that varies according to the installed capacity of the power station and a variable component that reflects grid energy losses. The price of the losses is set at the price of energy on the spot market and varies according to the location of the power station relative to the geographic configuration of the grid. There are power stations whose locations reduce the amount of line-losses, and thus their variable tariff component is negative. In regions where there is excess supply of production capacity, line-losses are relatively high and the variable charges are high. Since in the more urbanized areas there is a relative shortage of capacity, producers pay low, even negative, variable charges. It is noteworthy that the energy component charges vary by season and time of day. The point tariff for electricity consumption varies among power utilities and consists of three components: 1. A uniform fixed charge for all consumers connected at the same point to the grid.

116

Privatization and Restructuring of Electricity

Provision

2. A variable power charge that depends on the maximum demand (in kw). 3. An energy charge that depends on total energy consumed (in kwh). All consumers are connected at one of the following five levels of the grid: Level 1 Level 2 Level 3 Level 4 Level 5

Regional grid lines (130 kV, 50 kV). Main transformer (up to 20 kV). Local, high-tension lines (20 kV). Distribution transformers (up to 1,000 V). Low-tension lines (below 1,000 V).

Because of the method used to calculate fixed charges and the power charge, the actual price per kwh decreases as the total amount of energy consumed increases. Two types of electricity markets are organized and active in Norway. All power utilities, entities who buy electricity for resale, and large end users participate in the wholesale market. Most end users buy electricity from a local energy utility on the basis of long-term contracts or through the spot market. The various markets for electricity are operated by the transmission grid company, Statnett. Spot market contracts are negotiated for one day at a time. Separate contracts are negotiated for base-load and peak-load electricity in the weekly market. More recently, power brokers organized a market for options so as to reduce the uncertainty concerning future price fluctuations. The options to buy or sell electricity consists of a right, but not an obligation, to trade for an agreed-upon quantity at an agreed-upon price during a prespecified period in the future. In addition, a futures market consists of standardized contracts for the purchase and sale of electricity during a future period of time. As opposed to the options market, these contracts include an obligation to deliver and/or take electricity. Emphasis on Norway's unique generating plant and institutional arrangements leaves an impression that Norway's electricity system is isolated from its neighbors. This is contrary to the extant reality. For many years now, Norway trades electric power with Denmark, Finland, and Sweden. Differences in generating technologies in the Nordic countries, and the consequent differences in production cost structures, created profitable opportunities for trade. The largest trade volume takes place between Norway and Sweden, the two largest electric systems. Sweden accounts for 40 percent of the installed capacity in the Nordic block of countries. Norway accounts for 34 percent, while Finland accounts for 16 percent and Denmark for some 9 percent. In 1993, some 52 percent of the electric power generated in Sweden originated in hydro power and 44 percent in nuclear. In Finland, 22 percent originates in hydro power, 33 percent in nuclear, and some 45 percent in thermal. Denmark relies almost exclusively on coal-fired power stations.

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From Norway's perspective, trade with its neighbors is motivated by a need to supply peak demand by means other than the capital intensive hydro power. Thus, thermal plants from neighboring systems can supply midday peak demand, especially in the urban centers of the country. In addition to short-term contracts, Norway has medium-term contracts to account for shortfalls in generating capacity during years with low water supply. There are clear indications that the changes that were and are continually introduced in Norway are having a significant effect on the efficiency of the system. The structure of end-use contracts has changed. Wholesale prices have been reduced significantly. By the spring of 1997, some 10 percent of all the business customers have renegotiated agreements and recontracted for some 50 percent of the power consumed by this sector. In the process, prices have been reduced significantly. In order to encourage the renegotiation of contracts in the residential sector, the regulator has mandated a simplification of procedures and a reduction of the annual fee from NOK 4,000 to NOK 200 each time that a new supplier is selected. It is this continuing involvement of the public sector in the regulation of the competitive elements of the system that suggest that the forces of competition are not yet fully in control. Intense regulation and ownership have left the Norwegian public sector in control. It is theoretically possible, though yet to be verified empirically, that the efficiency gains are significant. Could a similar restructuring be carried out in a system that is not dominated by hydroelectric plants? It is conceivable that the repercussions in different systems could be significant. THE PACIFIC RIM Until the 1990s, New Zealand's electricity supply was dominated by a government-owned hydro power monopoly that set prices as well as standards of supply. At the retail end, local councils provided distribution services. Concern for the competitive position of electricity intensive industries in international markets led to end-use prices that did not reflect costs and to investment decisions that resulted in unjustified burden on New Zealand's taxpayers. It was the expressed intention of the New Zealand government to reach toward an ideal world in which New Zealand's electricity sector would experience a market with strong downward pressure on costs and consumer electricity prices. multiple generators selling to energy trading companies who in turn compete for customers around the country. new investment decisions are made by providers of private sector capital. a market where lines businesses are isolated from competitive activities such as generation, energy, marketing and metering. lines businesses provide access to any generator or energy retailer. lines businesses pass on efficiency gains to consumers as well as to shareholders.

118

Privatization and Restructuring of Electricity

Provision

contestable transmission services. a national grid operator focussed on lowering costs and pricing efficiently. no captive customers and choice for all consumers. a market where energy efficiency and conservation is an economically attractive option.2 To this end, restructuring of New Zealand's electricity industry begun in 1987 with the incorporation3 of former government departments into generation and transmission corporation. In 1993, distribution services were incorporated as well. In 1994, grid operations were split away from monopolistic Electricity Corporation of New Zealand (ECNZ), and the national grid operating company, Transpower, was created as a separate unit. In 1996, a significant portion of the generating assets of ECNZ were set up as a separate competitor, Energy Limited. During that same year, a competitive wholesale market was established. The establishment of the wholesale market followed soon after the introduction of completely deregulated direct access in 1994. The market brings together some forty distribution companies, with a number of generators under rules set up in 1996 and implemented by EMCO, who functions as a market clearing and price manager. The rules of the new market were set up jointly by all its participants (i.e., generators, purchasers, and traders). In a manner similar to Norway's market, buying and selling takes place through a pool. A spot market is supplemented by a whole range of forward contracts. It is a unique feature of the New Zealand system that the market operates in the absence of all but self-regulation. Prices within the market are not capped. It is too early to evaluate the operation of the wholesale market, yet it is clear that it has been dynamics. Higher rates of direct-access penetration are displayed by those with high direct costs, high utilization rates, low load factors and low system interruptions. The immediate reaction of the players in New Zealand suggests that market force can provide sufficient disciplining forces that preclude the need for government regulation. At this time, the New Zealand government is considering further steps to reduce the influence of any one player and to strengthen the forces of competition. Again, just as in Norway, competition and government ownership go hand in hand. Australia provides an alternative, yet unique, approach to creating a marketbased system while divesting of SOEs. To date, the Australian electricity system consists of several regional, state-owned systems. Each system has evolved and has been operating independently. In 1995, the Australian government has submitted draft legislation to implement a national energy market. This initiative represents a reaction to a series of practical steps taken independently by the states throughout the 1990s. The state initiatives, while variously motivated, included an explicit concern for privatization. Creation of SOEs from departments, restructuring, and the creation of appropriate institutions were deemed prerequisites to privatization.

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The experience of the New South Wales (NSW) electricity supply industry is a telling example of the process. By 10 May 1996, the NSW system has adopted a competitive structure. The process began with an experiment of Pacific Power to introduce an internal electricity exchange market in the summer of 1991. The experiment consisted of a wholesale, spot-generation market. The entire output was purchased at spot prices and resold to distributors and large customers under prices governed by regulated tariffs. The purpose of this initial experiment was to create an accounting system capability that separated the various elements of total costs into components and thus enabled later separation of functions. Profit centers and internal charging for products and services were introduced. According to Spalding (1996) the experiment resulted, among other things, in increased availability, reduced startup times, and reduced fuel usage. Another experiment was carried out at the national level in 1993 and 1994. It consisted of a paper simulation of a pool-based wholesale market that included almost two hundred participants from Queensland and South Australia. The experiment consisted of bidding and financial contracting. It provided an understanding of a variety of issues that formed the basis for the design of the wholesale market in NSW and the proposed national electricity market. The experience gained here, and in Victoria in 1994, led to a decision that proper operations of such markets requires the separation of the generation and transmission functions. In NSW, through two successive steps, the Transgrid was formed in 1995. It was charged with the implementation of an interim state market, until a national market is organized. At the same time, twenty-five local distribution authorities were organized into six state-owned retail and distribution corporations, and two generation corporations were split away from Pacific Power. The NSW wholesale electricity market began operations. CANADA—A VARIETY OF LOCAL INITIATIVES Canada's electricity system is organized according to provincial boundaries. Each province's system has evolved over the years according to local conditions and traditions. There exists a great diversity among the provinces in terms of the economic conditions, performance, and traditions. Upper Canada, mainly Ontario, is part of the U.S. industrial belt located in upper New York State. Eastern Canada's economy is much less developed and economically progressive than Western Canada which, while resource rich and less industrialized, is progressive and innovative. The provincial electric systems are quite similar. Vertically integrated utilities, often government owned, dominated the industry prior to the current restructuring and privatization initiatives. Alberta, Ontario, and British Columbia are good examples of the issues that dominate and the changes that are taking place in Canada. To this day, electricity generation and transmission in Ontario is in the hands of a provincial, government-owned monopoly, Ontario Hydro. Distribution is

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Privatization and Restructuring of Electricity Provision

carried out by some 307 local, mostly municipally owned, distribution companies. Despite its name, Ontario Hydro owns nuclear power stations, hydroelectric facilities, and fossil fuel plants. Thus, Ontario's electricity system is a government-owned monopolist. Despite the separation of generation and transmission from distribution, the system behaves like a vertically integrated monopolist, not unlike that in other countries such as Israel. In March 1996, a politically powerful Advisory Committee on Competition in Ontario's Electricity System released its report to the provincial government. The investigation was launched in order to design a mechanism to cope with conditions that are both apparent and implied. Electricity bills in Ontario are clearly the highest in Canada (see Table 7.2). The Committee's declared charge was to investigate mechanisms to modernize the electricity system in Ontario and to lower the burden of electricity bills in Ontario. More important, if less apparent, at the backdrop of the Committee's deliberations was the inevitable influence of the massive changes taking place in the neighboring electric systems to the south in the United States. The Canadian economy, and that of Ontario in particular, has been suffering from decreasing competitiveness. It was expected to be aggravated further by the far-reaching effects of the North American Free Trade Agreement (NAFTA), which has caused a process of industrial restructuring. Some sectors have become entirely uncompetitive, while other sectors have benefited from the lowering of barriers to trade. To cope, Canada has begun a process of restructuring its welfare state with the hope of making prices of productive resources competitive. It is in this context that recommendations of the Ontario Committee should be understood. Restructuring and privatization are at the heart of the Committee's recommendations. The committee declared that modernization means making the power market competitive. In the proposed marketplace, electricity prices will be set by producers and consumers together "in a climate of open and fair competition, rather than in the boardroom of Ontario Hydro."4 Two new independent agencies were proposed. The physical dispatch of electricity will be in the hands of an independent system operator, whose responsibilities will include ensuring that all buyers and sellers have access to the transmission system. The system operator will be organized as a nonprofit corporation. It will charge for its services, so as to recover its justifiable costs. Transactions will be supervised, accounts will be settled, and financial integrity will be assured by the Electricity Exchange. The Exchange will incorporate within it all the electricity players, generators, energy service companies, purchasers, agents, brokers, and marketers. The Exchange will operate a futures market. It also will be a nonprofit entity who will recover all justifiable costs. The Committee recommended to divide the generation facilities of Ontario Hydro among several new economic players. Several new government-owned companies will own the existing nuclear power stations and the heritage hydroelectric facilities at Niagara Falls. Nuclear facilities will operate as four

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The World Beyond Table 7.2 Typical Monthly Electricity Costs in Canada by Location, 1994 (in C$) Region

Billing Demand Consumption

Residential Sector

1,000 kWh

Commercial Sector

100 kW 25,000 kWh

Industrial Sector

1,000 kw 400,000 kwh

Toronto

101

2,826

34,500

Halifax

97

2,742

26,982

St. John's

86

2,581

24,355

Regina

84

2,772

33,221

Fredrickton

80

2,310

22,820

Calgary

71

2,139

22,400

Vancouver

67

1,683

19,976

Montreal

66

2,328

21,715

Winnipeg

63

1,793

19,092

Source: Natural Resources Canada, Electric Power in Canada, 1994, www.nrcan.gc.ca, 21 June 1996.

separate competing entities. The remaining hydroelectric plants and all the fossil fuels stations will be privatized. The hydro plants will be organized according to the relevant river systems. Their number and size will be determined so as to prevent any one generating company from exercising excessive market power. Generators from out of Ontario will have equal access to electricity consumers in the province. The Committee recognized that the historically determined configuration of municipal distributions systems may not be economically optimal, and indeed it may not be viable. The Committee recommended that the number of distributions utilities be reduced through a gradual process, mainly influenced by market forces. Finally, the introduction of competition should take place in two separate phases. In the first stage, wholesale competition will be established. Generating companies, including those owned by the government, will compete for sales to large industrial users of electricity and to municipal distribution utilities. In the second stage, the Committee recommends the development of full-scale retail competition.

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Privatization and Restructuring of Electricity Provision

To ensure nondiscriminatory access to the transmission grid, the Committee recommended that the transmission assets of Ontario Hydro be set up as a separate Transmission Grid Company. The new company will charge a uniform levy for access, "postage stamp rate." Access charges will be the mechanism to accomplish other public policy objectives as well. Indeed, access charges are a good mechanism to redistribute the burden of the expected stranded costs among those who will benefit from the reforms. To provide proper price signals and to ensure that the grid system expands according to need, usage price will reflect congestion. The restructuring proposals include recommendations to establish a regulatory mechanism that is appropriate for the competitive environment that the Committee proposed. To ensure that the productivity gains and costs savings that are expected as a result of the new regime will be shared among the regulated bodies and customers, the Committee recommended incentive regulation, such as those described in Chapter 3. Indeed, the same type of regulation should be implemented in the case of all parts of the new electricity system, including transmission and distribution price regulation. A similar set of issues is being debated in British Columbia (BC). The BC electricity industry consists of 13,300 MW of installed capacity, 85 percent of which is hydroelectric. It produces 60,000 Gwh of electric power annually. The industry is dominated by the government-owned, vertically integrated British Columbia Hydro and Power Authority. It supplies almost 90 percent of the electric power in the province. The rest is supplied by one larger private and several very small private and municipal, vertically integrated utilities. All the utilities, except municipals, are regulated by an independent agency, the British Columbia Utilities Commission (BCUC), whose charge includes examination of the prudence of expenditures incurred and the setting of rates. As in many states to the south, the BC agency bases its judgments on future-year cost-of-service studies and integrated resource plans that include demand-side management. In December 1994, the provincial government mandated the BCUC to conduct a public review of the electricity industry in BC, with a particular emphasis on an examination of the feasibility of retail-wheeling. At the backdrop of the investigation were changing conditions and concerns of BC political leaders. Three "forces for change" were cited by BCUC: • Changes in generation technology have decreased, if not eliminated, economies of scale in generation and thus reduced the need for a natural monopoly. • The increasing globalization of the BC economy places a heavy burden on the competitive position of BC industry, especially the electricity intensive sectors. • The increasing public skepticism concerning the need for government ownership of nonessential industries.

There is no doubt that BC's traditional search for advancement, and the reforms in the United States, the United Kingdom, and in the neighboring province of Alberta, influenced political leaders to initiate the process.

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The BCUC conducted a process of public hearings to investigate options and possible benefits and costs, as well as to evaluate public opinion concerning possible alternate policies. A very clear consensus revealed that some incremental changes are needed. Some industrial users of electricity called for step-by-step, but clearly defined, movement toward retail competition. Many expressed concern over the ability of the government to advance environmental and social policies in a context of restructured industry. The extensive embedded costs in BC's hydroelectric plants were also cited as a good reason not to promote drastic and quick changes. The final recommendations of the BCUC are minor, careful, and much more limited than those in Ontario. The conservatism in BC is clearly evident in the variety of small steps that were recommended. The recommendations are divided according to the proposed time scale of their implementation. In the short run, BCUC recommended the preparation of information that might be useful, should restructuring take place at a future date. Thus, all integrated utilities were mandated to create separate divisions for generation and transmission assets. Eleven utilities owning transmission facilities were required to submit proposals for separate transmission tariffs, while eliminating crosssubsidies. In the long term, BC utilities were required to create separate corporate structure for their generation assets and to propose a structure for wholesale competition through a pool. In fact, there is no recommendation to implement de facto wholesale competition. The BCUC limited itself to recommending an examination of such an option, while clearly rejecting retail competition in the foreseeable future. A radically different approach was taken by the province of Alberta. In 1995, it passed legislation that completely restructured the electric utility industry in the province. In fact, Alberta has become by far the leading reformer in North America. In one swoop, it sorted out the various institutional issues that have been objects of discussion in every jurisdiction that has considered reforming its electricity system. It is noteworthy that, relative to other provinces, Alberta's electricity consumers enjoyed relative advantage in quality and price of electricity prior to the reforms. There was no pressure from consumers to reduce rates or improve quality. Yet, a general consensus over the need to make changes, as well as over their nature, resulted in a quick and bold move. Only two years passed from the initial statement of inquiry by Alberta's Minister of Energy concerning the way that Alberta should go, until the implementation of the Electric Utilities Act on 1 January 1996. Three privately owned, vertically integrated utilities dominated the electric industry of Alberta. They were supplemented by a variety of municipal systems owned by local authorities. Though Alberta's grid was interconnected with the rest of the western United States and Canada, its electricity was competitive. Thus, it is unclear what were the true motives behind the following stated reasons for the legislated reforms: • To establish an efficient market for generation based on fair and open competition.

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Privatization and Restructuring of Electricity Provision

• To ensure that the benefits and costs associated with existing, regulated plants continue to be shared equitably by current and future customers throughout the province. • To ensure that investment in new generation is guided by competitive market forces. • Where regulation is still necessary, to minimize its cost and to provide incentives for efficiency.

The main element of the restructured system is the open access to the grid that is ensured by the newly established Grid Company of Alberta Inc., which was appointed as the transmission administrator. The administrator contracts with owners of parts of the grid for the delivery of transmission services at a regulated and nondiscriminatory price. Thus, while elements of the grid are owned by various companies, the administrator ensures accessibility. The second element of the system is the newly established power pool that enables trade for electric energy on an hourly basis. It is operated as a cooperative overseen by a council with representatives from all participants in the pool. The distribution of electricity will be carried out by local regulated monopolies who have an obligation to serve at a regulated price. Customers need not buy electricity from their local distributor, who in such a case must provide grid services at the regulated price. Two more aspects of the Alberta reforms are noteworthy. First, the regulated rates for transmission and distribution services will be subject to incentive mechanisms so as to reduce the cost of providing monopolistic services. Second, the proposed changes do not require divestiture of generation assets by owners of transmission and distribution assets. The vertically integrated utilities need to reorganize by setting separate business units that will provide transparency for the regulated activities. Regulation is deemed a sufficient mechanism to prevent cross-subsidies as a barrier to competition. Thus, while Alberta has declared a full-fledged reform that sees in competition the principal mechanism for regulating the province's electric industry, de facto institutional arrangements that protect competitive arrangements are limited in scope. To the outside observer, Alberta's effort is bold in intentions, if not justified by extant interests, and limited in institutional development, so as to ensure its success.

THE DEVELOPING COUNTRIES The main concern at the backdrop of the electricity restructuring efforts that swept the developed economies in the 1990s was improved efficiency, both allocative and technical. In the developing countries, the main issue has been and continues to be concern over the provision of basic electricity services to a greater portion of the population, especially in rural regions. In the United States, rural electrification was accomplished with the help of governmentowned companies that overcame the high cost of providing electricity in remote and low population-density areas. At the end of the twentieth century,

125

The World Beyond

almost 70 percent of the rural population of the developing world remains without electricity. Despite its access to the wires network, almost 25 percent of the urban population in the developing world does not enjoy access (see Table 7.3). Electrification in the developing world requires massive investments. There are many countries where the population's annual per capita income is below U.S. $500. In such countries, even the most basic energy needs, such as cooking and heating, are met by burning wood or dung. As annual per capita incomes reach U.S. $1,500, these needs are met by more modern energy forms. The skewed distribution of income that characterizes developing economies means that the average income needs to be much higher before all the population demands and can afford electricity services. Subsidies and geographically uniform electricity rates have been a major obstacle to rural electrification. Subsidized electricity prices leave small, sometimes negative, profit margins and thus discourage the formation of small, local electric companies from entering the rural market. At the same time, nationwide utilities have no incentives to serve rural customers who contribute the same revenues per unit as urban customers, but are much more expensive to serve. Subsidies create distortions in the consumption and production decisions and generally tend to benefit the higher income households. To improve the chances of introducing electrification to rural and urban poor populations, it is necessary to lower system costs by technological improvements, to provide financial credit to certain population groups, and to

Table 7.3 Population Connected to Electricity in Developing Countries Urban 1970

Urban 1990

Rural 1970

Rural 1990

North Africa and the Middle East

65

81

14

35

Latin America and the Caribbean

67

82

15

14

Sub-Saharan Africa

28

38

4

8

South Asia

39

53

12

25

East Asia and the Pacific

51

82

25

45

All Developing Countries

52

76

18

33

Total Served (in millions)

320

1,100

340

820

Region

(%)

(%)

(%)

(%)

Source: World Bank, Power and Energy Efficiency Status Report on the Bank's Policy and IFC's Activities, The World Bank, 1994, 16.

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Privatization and Restructuring of Electricity

Provision

create lifeline rates for the wires business. Thus, for example, the design of distribution systems that are capable of delivering between 3 and 7 kw of service to rural households create excessive costs because of the need for heavier wires and larger tranformers. Most customers in rural areas need minimal service, from 0.2 to 0.5 kw. Similarly, the 50-watt photovoltaic systems that are promoted by various international organizations are in excess of the requirements and means of these customers. Recently, in Indonesia, Nepal, and Peru, banks and nongovernment organizations are providing affordable credit to make access to a grid affordable, especially to small, microhydroelectric projects. In many countries, rural poverty exists alongside fairly developed urban economies. Demand for capacity to meet rural needs exists along a growing need to meet expanding urban economies. These needs cannot be met by governments, and thus there are increasing discussions and actions to introduce private capital. The institutions considered are not unlike those being introduced in the industrialized world. NOTES 1. The original proposal by the European Commission, titled The Internal Energy Market, was published in 1988 (COM[88] 238). 2. Max Bradford, Minister of Energy, "New Zealand Electricity Industry— Towards a Competitive Market," address on 12 September 1997. 3. The creation of corporation from government units has been termed in New Zealand "corporatisation." 4. Speech of Donald S. Maedonald, Chairman of the Committee, 7 June 1996.

8 Concluding Remarks

The modern electricity industry began as a myriad of small, local, and highly competitive private initiatives. The early vertically integrated companies were not regulated. Entrepreneurial spirit and fierce competition for new customers and new markets mandated that great attention was devoted to constant improvements in technical and allocative efficiency. Early electricity entrepreneurs were keen to best serve their customers by providing them with new and ever-improved products that customers required and expected, and at a competitive price. Persistent technological innovation led to the realization of economies of scale. Mergers and takeovers followed mergers and takeovers. Investors, many of them bankers, were not technologically competent. Their keen interest was in an ever-greater return on investments, and much beyond the risk inherent in the early electricity industry. The industry was in constant flux. There was a thirst for the type of quiet business life that comes with advanced stages of the typical product life-cycle. There is little doubt that it was the initiative of the electric industry that created the prolonged industrial peace, which was achieved through the creation of regulation and the regulatory compact, presumably as a mechanism for the protection of consumers, but de facto as a barrier to competition. Reduced rates of return on investments were the price that was paid by the industry, in return for regionally defined monopoly rights and some seventy years of quite business life without competition.

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Privatization and Restructuring of Electricity Provision

The price of the industrial tranquility that was the result of the regulatory compact was paid not only by investors, who recieved returns on investments that were as low as the risk of doing business. Salaries in the industry were lower than in equally sized, but riskier, businesses. There were exceptions. In Israel, for example, salaries in the state-owned Israel Electric Corporation were the highest of any industrial concern. Above all, the price was paid by customers who bore the burden of technical and allocative inefficiency, just as it is predicted in the A-J and Henderson-Czamanski models. Change could have been expected as a result of benefits to be recieved by any of the actors who would be willing to give up the queit life in return for real and pecuniary benefits. After so many years of incremental, almost imperceptible institutional changes, something triggered what seems to be a revolution. Regulatory protection is giving way to competition as the primary disciplining mechanism. Rivalry in the marketplace is replacing collusion and decision making in smokefilled rooms. Vertically integrated utilities are breaking up in favor of economically lean and flexible organizations. It is striking to visit management floors of a modern electric company headquarters and to meet the new generation of executives. Their age and professional training stands in marked contrast to the characteristics of old-time utility managers. Young, businesstrained professionals have replaced the older and experienced engineers. The nature, extent, and timing of the change is nothing but noteworthy. The change was inevitable. The opportunity to make money and to create returns beyond those made possible by the regulatory social contract was there all along. The perplexing phenomenon is the prolonged survival of the regulatory compact and the protection from competition that regulation afforded the industry. It is curious that there were no clearly visible attempts from outsiders to enter the industry. Rent-seeking was not apparent. The revolutionary processes described in the previous chapters began with the Yom Kippur War in 1973 and the OPEC-induced oil shortages in the Western economies. The shortages, first of oil, then of natural gas, and finally of electric energy, made apparent that rent-seeking behavior did not disappear from the board rooms of regulated monopolies, even though it lay dormant for several decades. The 1970s were characterized by great diversity. Utilities began to interconnect on a massive scale. Power pools began to operate to overcome spot shortages. Procedures for power pool management became a topic of debate among utilities. Some utilities improved their returns on investments by riding the waves of reduced production, while others experienced devastating losses and caused regulators to start performing their function as protectors of consumers. Sharp upward pressures on prices created a need to evaluate requests for rate increases. After decades of declining average rates and declining-block tariff structures that were constructed to promote consumption, utilities initiated flat tariffs, and even inverted-block structures were being evaluated. Requests for rate increases and energy shortages created an atmosphere for evaluating utilities' cost performance and for creating incentives for improved

Concluding Remarks

129

efficiency. The early attempts were limited to the increasing standardization of cost examinations and the eventual creation of common-cost allocation procedures. Local conservation efforts were promoted mostly through subsidies and occasionally through appropriate tariff structures. It was in the context of conservation efforts and environmental concerns that PURPA created the concept of an independent power producer. In the beginning of the 1980s, regulators became familiar with the concept of incentives and regulation that went beyond the mechanical translation of recognized costs into tariffs. Regulatory proceeding were focused on selective treatment of various cost elements and appropriate tariff structures that can be used to influence behavior. The stage became ripe for the introduction of competition as an incentive mechanism to improve the sector's cost performance. While academic studies confirmed what was already known to practitioners, generation economies of scale became a nonissue. The introduction of combined-cycle natural gas plants that competed successfully with base-load plants made small generating companies economically possible. Wholesale competition required nondiscriminatory transmission and distribution rates. Unbundling of rates and proper accounting for the cost of the wires-business became the major issue in the 1990s. On the eve of the twenty-first century, the following statements represent a fair summary of the state of thinking in the electric industry: • Electric energy is a private product that can be produced and sold within a competitive market. • The wires-business remains a natural monopoly and should be regulated so as to create a level field for the competition game. • Business rivalry through market institutions provides sufficient incentives to ensure technical and allocative efficiency in the electric energy market. • Cooperatively created market mechanisms are sufficient forces to assure future supplies. • Social and environmental policy concerns can be served through the regulated prices of the wires-business and in particular through differential access charges. • Government ownership of production infrastructure is required at the margin only and in situations characterized by extreme externalities. No doubt, there are clear exceptions to the universal applicability of these statements. Rent-seeking is a poor incentive mechanism to achieve universal electrification in those regions of the world where the willingeness to pay, and more appropriately, ability to pay, is below that which can compensate investors for the risk of building up electric infrastructure. In such situations, private initiative could be expected to perform the task, but only in countries with governments that have created institutional stability, and by so doing, have reduced business risks. Such stability is possible in places that are politically stable, and thus assure investors revenue stability. Exchange rate regimes make foreign investors unable to take out their investments along with a rea-

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Provision

sonable return on their investments, and yet, governments would be required to subsidize local electricity prices. Until recently, the international investment banking community was doubtful that developing countries could create the environment requisite to make private capital involvement possible. The last decade has witnessed the beginning of an electricity privatization process in the developing world. While the World Bank points out the successes, the actual process is often hesitant, and more often, stalled. The banking consortia, created so as to distribute risks to the maximum extent possible, are increasingly difficult to organize. It is interesting to speculate whether the current financial crisis that is sweeping the world, from the East to the South, and possibly to the industrial world, will affect privatization efforts for the decade to come, and perhaps beyond. While market forces are stalling privatization efforts in the developing world, there are aggressive opponents to privatization in the most advanced economies. In Norway, western Canada, and several other places, competition among government-owned electric companies is deemed to be an institutional arrangement that can achieve maximal efficiency. No gains from private ownership are deemed justified by the costs of giving up public ownership of vital resources. This is particularly true in the context that publicly owned companies are forced to compete with private companies. In these countries, cheap hydro power is abundant. As a result, improvements in efficiency that could be expected from the introduction of private rent-seeking, while reasonable, would be so small in absolute terms as not to be justifiable. It is too early to evaluate the restructuring and privatization efforts that have been introduced heretofore. There are clear indications that restructuring leads to a decreased burden on the consumers of electricity. The evidence is sketchy, and is obscured generally by extraneous influences. The generally declining electricity rates mask the influence of restructuring. More important, the restructuring measures are being introduced gradually. The current experience is very short and in very few places. We must observe the phenomenon for the next ten to twenty years before passing the final judgment. Yet, there are unequivocal reasons for advocating restructuring for those countries that have not yet adopted such a strategy. Above all, there is no technological imperative for monopolistic arrangements, nor government involvement, in the production and selling of electric energy. It is important to note that restructuring and privatization processes, just like all institutional changes, are costly. Some of these must be clearly identified and listed. Generally, there is no appropriate legal framework within which to implement the desired changes. The requisite legislative actions are complex, and generally, they lead to exchanges within the political marketplace. Often these lead to the introduction of distortions and misallocation of resources in other and unrelated sectors of the economy. More directly, the exploitation of rents through markets requires an institution, such as an independent system operator and power exchanges. The organization and op-

Concluding

Remarks

131

eration of these new institutions is not without cost. It is not clear that under all circumstances the new costs are justified by the gains that they make possible. This is particularly true in highly hydro power intensive systems, such as that in Norway. Similarly, there is no need to perform sophisticated and prolonged studies to justify market forces into monolithic, government-owned, and highly inefficient electric systems, such as that in the state of Israel. Finally, a note of warning. The introduction of private players into the generation of electric energy and into the selling process creates an opportunity for system abuse. Mergers and collusive practices can create inefficiencies that are no less problematic than the inefficiencies caused by traditional public utilities. The regulation of private utilities is not easier than the regulation of government-owned companies or departments. To prevent excessive concentration and market power, there is a need to create a mechanism for identifying abuses and for disciplining the actors. The electric industry has no tradition of dealing with measuring and controlling market power. It is high time to begin creating institutions for the task. The absence of institutional sophistication in some countries may prevent the introduction of market forces into the electricity industry. The myriad of exprerience suggests that the decision to restructure should be preceeded by a careful process that prepares for decision making and molds the actual decisions taken. A well-considered process can bring about improvements in technical and allocative efficiency and at a minimal cost. In most cases, it can prevent the process from stalling or from being sent off in an undesired direction, or derailing altogether. A derailed process can generate costs much greater than the maintenance of the status quo. In countries that have carried out the process successfully, the first step has consisted of the clear identification of all the players, existing and future, small and large, in the life of the electric system. As part of dynamic, strategic policy making, the interests of all the players need to be clearly mapped out. Since these interests are affected by specific conditions, it is imperative to examine the way that these interests are affected at each step of the decision-making process. Next, it is important to map out all possible structural alternatives. It is imperative that the various alternatives include as many of the possible, even if not desirable, alternatives that can emerge from the strategic interactions among the players. Such an analysis may reveal some of the bidding constraints on the restructuring road. Moreover, it can help in the estimation of the implementation costs, including the costs of removing some of the constraints. Before embarking into decision making, it is important to evaluate the relation of benefits to costs under the various alternate restructuring plans and a variety of expected scenarios. It is the strategic analysis of alternate plans evaluated under various scenarios and summarized through benefit-cost statements that yields a proposal for the overall restructured system. A public debate process concerning the proposed structure should preceed a similar evaluation of detailed alternatives and the eventual legislative process.

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Privatization and Restructuring of Electricity

Provision

The legislative process may lead to structures that were not foreseen by the early strategic plans. In such a case, an iteration of the strategic analysis should be performed in order to evaluate the feasibility of the structure and its desirability in light of the estimated benefits and costs. Should this analysis lead to positive conclusions, a detailed implementation plan should be prepared. A limited trial experiment should be implemented prior to an evaluation and before a massive implementation of the proposed structure. It is important to plan for a prolonged period of fine-tuning the operation of the new structure. Indeed, the process of restructuring should be viewed as a continuous, never ending, process of adapting the electric system to new technological, economic, and political realities.

Appendix

In the basic model, the regulated firm is assumed to maximize profits, defined as the difference between revenues, labor costs, and capital costs. Revenues and costs experienced by the utility are a function of the relevant marketdetermined prices and the utility-determined quantities. Thus, 71 (L,K) = R(L,K) - wL - rcK

(A. 1)

where n stands for profits, L for physical units of labor, K for physical units of capital, R for revenues, w for the constant wage rate per unit of physical labor, c for acquisition cost per physical unit of capital, and r for the constant, marketdetermined cost of borrowing funds. The firm is presumed to maximize profits by selecting L and K, subject to regulatory constraint, in the form of s, the maximum allowable rate of return on investments. Given that s is greater than r, the firm's constraint is

The model assumes that the regulator determines the maximum allowable rate of return on investments, s, and the firm adjusts its price and other decision

134

Appendix

variables in accord with s. Thus, the price adjustment is an implicit, rather than explicit, component of the model. Labor input, L, is the total man-hours worked, and the average cost per man-hour, w, is assumed constant. Capital input, K, is units of capital, and cK is the cost of tying up the assets required for production. The capital cost includes the cost of physical plant, such as plant and equipment, as well as financial assets, such as working capital. Thus, cK is the capital stock in dollar terms. Since c is constant, the firm does not influence the price it pays for capital goods, and cost of capital, r, is the minimum return the firm must earn in order to secure its ability to raise funds over the long run. The cost of capital is assumed to be known and independent of the mix of financial instruments used. The rate-of-return constraint in equation (A.2) can be translated into a profit constraint by multiplying both sides by cK and subtracting from both sides rcK. The result is what Baily (1973) termed a profit ceiling: n ^ (s - r)cK

(A.3)

In Baily's terminology, rate-of-return regulation is in fact a profit-ceiling regulation, under which the profit ceiling increases with increased use of capital. In this variant of the well-known Averch-Johnson (1962), or A-J model, it is clear that the regulated firm may adjust its use of inputs other than capital without limiting its profit potential. The ceiling is independent of increases in labor usage, but the choice of capital is an explicit determinant of the profit ceiling. In the context of the A-J model, it is useful to think of profit as a random variable. If unconstrained profits are larger than those permitted in the regulatory framework, then equality holds in the constraint, and the firm will obtain maximal profit if it earns the maximum return permitted by the regulator. In this case the firm's objective is maximize

(s - r)cK

(A.4a)

subject to Figure A. 1 illustrates the profit function of a hypothetical profit-maximizing firm operating under a regulatory rate-of-return constraint. Point M on the profit hill represents the combination of capital and labor that yields maximum profits to the firm. The regulatory constraint precludes the firm from earning M profits. The constraint is the ray passing through the origin with a slope (s - r)c. The locus of possible combinations of inputs yield possible profits on the ABDE curve. Point D indicates the solution to the profit maximization problem. At this point, the firm will employ F quantity of capital, instead of C, that is, the quantity that an unconstrained firm would have utilized. Since F > C, the regulated firm employs more units of capital than it would employ if the constraint were eliminated.

Appendix

135

Figure A.l The Profit Function of a Firm, Subject to a Rate-of-Return Constraint

Source: Adapted from E. E. Baily, Economic Theory of Regulatory Constraint (Lexington, Mass.: Lexington Books, 1973), 71.

The A-J model is a useful paradigm for examining the repercussion of behavior on the part of utilities and regulators that deviates from "proper" behavior, such as setting the allowed rate of return equal to the market-determined required return on investment. The A-J effect implies that capital waste comes about only if the allowed rate of return exceeds the cost of capital. Overcapitalization occurs when the regulator is guilty of misidentifying the true cost of capital. The A-J thesis allows the firm to operate off the production frontier, since earnings above the cost of capital that lead to higher costs are rewarded via higher rates. Inefficient operation will continue as long as the utility is allowed to earn more than its cost of capital. Until the mid-1970s, Morton (1971) and many others contended that regulators sometimes seek to encourage efficiency by allowing the utility to earn a rate of return that exceeds its cost of capital, as long as the utility achieves this rate through efficient operation. However, a regulatory commission dedicated to efficiency and eliminating misallocations of resources will take away the excess earnings, even if the utility earned a return above cost of capital due to its superior efficiency. But, can the utility, let alone the commission, identify the opportunity cost of capital so that the allowed rate of return will be equal to it over time? At best, this is a difficult task. Efficient management will attempt to identify the lowest-cost combination of resources. Such an effort requires information on current and projected changes in factor prices, the elasticity of demand, scale of output, changing technology, relative prices, and other economic factors.

136

Appendix

Thus, the least-cost combination of factors is at best an estimate that will change continuously as existing plants, processes, and relative prices change. Proponents of regulatory disciplining prowess suggest that changing economic circumstances are capable of penalizing utilities for inefficient decisions and thus supplement regulators' toolbox. At the same time, the existence of a tight ceiling on profits may create a disincentive for efficient operation. The managers may become less cost conscious. Because of the moral hazard problem, it is not desirable to strip the utility of all incentives to reduce costs and to improve service, even if it were possible to limit the utility's earnings to a fixed amount. It may cause the utility to become reckless in its efforts to control expenses. In the profit maximization framework, the existence of redundant expenses is a result of regulation. The situation may be in fact worse still, in that the utility may not be a profit maximizer. Indeed, it may prefer expenditures on staff and/or advertising that increase sales. To examine this situation, there is a need to change slightly the definition of profits. Now the utility's profits, 71, are defined as n = xP(x, A) - wL - pK - A - S

(A.5)

where x is the quantity of output, P(x, A) is the inverse demand function, w is the constant price of labor, L is the quantity of labor input, p is the constant cost of physical capital, K is the physical quantity of capital, A are expenditures on advertising, and S are expenditures on staff. It is assumed that x is a quasiconcave, neoclassical production function and S exceeds S*, the minimal expenditure on staff sufficient to sustain an output and advertising expenditure A. In expense-preference models, such as that of Crew and Kleindorfer (1979), the firm maximizes a utility function, U(S, n). The objective of the expense-preference regulated firm may be stated as follows: maximize

U(S, n)

(A.6a)

subject to

S ^ S x (x, A)

(A.6b)

x ^ F(K, L)

(A.6c)

n = xP(x, A) - wL - pK - A - S ^ (s - p)K

(A.6d)

x, K, L, A, S ^ 0

(A.6e)

where s (s > p) represents the allowed rate of return. Formally, the problem can be stated as: L = U(S, 71) - 11 {S - S x (x, A) + n2 [F(K, L) - x] + n (s - P)K - 71}

(A.7)

137

Appendix

where \iv |i2, and JLX3 are the Lagrangian multipliers. From the first-order conditions necessary for a maximum solution, and assuming that Fl > 0 and F2 > 0, it is possible to derive the following in Baily's terminology: qk / q, = (re / w) - [JLL3 / (|i2 - |Lt3)] [(s - r)c / w]

(A.8)

Thus, the expense-preference model yields a result that is consistent with the profit maximizing model in that the regulated firm is not cost minimizing. The firm employs too much capital and too little labor. The overcapitalization persists for the expense-preference firm unless s = p. This result is illustrated in Figure A.2. As the regulatory constraint is tightened from s{ to s2, profits decline from N to D, but the firm responds by increasing the use of capital, to level F instead of O. For the expense-preference firm, the A-J effect is zero when s equals (3. Changing s in the constraint has the effect of changing the effect profit has on the value of the objective function. As s approaches (3, a dollar invested in an additional unit of capital has decreasing attractiveness relative to spending the same dollar on staff. Thus, as the allowed rate of return decreases and K increases, staff expenditures must also increase. Regulation has the effect of substituting inefficiency in the use of staff for the A-J type of inefficiency in the use of capital. Even the early corporations were subject to workers' and managers' taste for nonproductive activities, such as perquisites and/or leisure, at the expense of the firm's profits. Such maladies of the modern firm, caused by an organiFigure A.2 Responses to Tightening Rate-of-Return Constraint (Sl > S2)

Source: Adapted from E. E. Baily, Economic Theory of Regulatory Constraint (Lexington, Mass.: Lexington Books, 1973), 90.

138

Appendix

zational structure in which ownership and management are in separate hands, were studied extensively first by Jensen and Meckling (1976). Any perfect monitoring of perquisites and associated enforcement mechanisms, such as Fama's (1980) perfect labor market for managers, would make regulatory monitoring unnecessary and zero profits optimal. Until quite recently, however, wage contracts in regulated industries did not typically provide penalties for imprudent behavior. Furthermore, since the profit motive that drives stockholders to reward or to punish new managers for past behavior is diluted by the regulation itself, managerial mobility among a regulated firm would not appear to provide the same disciplinary force as is suggested by Fama's competitive example. Thus, it is necessary to assume that other forces that may discipline managers are imperfect. The regulator has two instruments with which to influence the manager's behavior: the allowed rate of return and the monitoring of wasteful behavior. In the absence of product market competition, utility managers' taste for nonpecuniary benefits is assumed here to have no productive component whatsoever. The manager's "quiet life" is an often quoted illustration that captures the essence of nonproductive expenses. In the Henderson-Czamanski model (Czamanski and Henderson 1981), nonpecuniary benefits, or shirking, is denoted as S. The manager chooses productive activities and S so as to maximize his utility U[S, B(7c)], where n is profits and B(7C) is a profit-sharing formula, such as an + b(7t), where a is the manager's share in the firm's stock and b(7c) is a pure profit-dependent bonus. To simplify matters, we assume that the firm combines labor and capital in fixed proportions, at the expense of an inability to analyze A-J-type overcapitalization. By an appropriate selection of measurement units, the constant returns to scale, and fixed proportions technology can be represented as constant costs with profits written as n = P(x)x - cx - S

(A.9)

where P(x) is the inverse demand function, x is output, and c is marginal cost. While typically the rate of return constraint allows a fair return on capital, in this model it is expressed as a return on output: P(x)x = R(x) ^ rx + S - D(S, M)

(A. 10)

where R(x) is revenue, r is the regulated rate of return per unit of output, and D(S, M) are those nonpecuniary benefits or wasteful expenditures that have been discovered by the regulator through monitoring activities. We assume that zero monitoring discovers nothing, [D(S, 0) = 0], and that only a fraction of waste is indeed discovered, (0 < D s < 1), while more careful monitoring uncovers more waste (DM > 0). It is noteworthy that discovered waste while excluded from allowed revenue is in fact included in profits.

139

Appendix

These assumptions lead us to the following optimizing behavior on the part of managers: L = U[S, B(TC)] - A,[R(x) - rx - S + D(S, M)]

(A. 11)

where X is the regulatory shadow price. The first order optimum conditions require: L = B'U 2 (R' - c) - A,(R' - r) = 0

(A. 12a)

L = U, - B ' U2 + UI - D ) = 0

(A. 12b)

Z^ = R - r x - S + D = 0

(A. 12c)

Without the restriction of regulation, the manager of a monopoly would select the output that equates marginal revenue and cost and consume perquisites until Uj/U2 = B \ This is the well-known Jensen-Meckling insight that partial ownership changes the relative price of nonpecuniary benefits, since outside owners pay a portion, 1 - B', of the manager's quiet life. Condition (A. 12b) shows that regulation drives a wedge between the marginal utility of perquisites and marginal utility of money profits. Since B'U 2 - U{ = X(l - Ds) > 0, the manager responds to regulatory pressure by consuming more fringe benefits, thereby driving their marginal utility lower. The stockholders have no way of converting managerial waste into profits. The Jensen-Meckling capital market disciplines the manager by forcing down the stock price of new shares offered as the owner reduces his share of the firm. No similar mechanism exists as the regulator reduces the allowed rate of return. In the limit, for example, if stockholders could extract profits at management's expense, these would be subjected to the regulation and eliminated. Hence, stockholders have no incentive to discipline managers in response to regulatory action. The capital market, however, can protect itself against a reduction in management's ownership share a in the same fashion as Jensen and Meckling discussed for the unregulated firm. The only difference for the regulated case is that the market must anticipate that output is likely to fall as a is reduced, whereas it remains constant in the absence of regulation. The manager's equilibrium is illustrated in Figure A.3. Point A at the center represents the manager's choice of productive and unproductive activities in an unregulated monopoly environment. At point A, utility is at a maximum. The regulation-determined constraint for some r > c lies to the northeast of A with the feasible region to the northeast of locus II. Point E represents the regulated manager's best choice. Here, his indifference curve is tangent to the nonlinear constraint I. Through comparative statics analysis, it is possible to show that repercussion of tightening regulation. If output and perquisites are normal goods, a

140

Appendix

Figure A.3 Manager's Equilibrium

lump sum reduction in allowed revenue results in more consumption of each. The income-effect component of reducing the regulated rate of return, then, normally induces both more output and more waste. The substitution effect is represented by a reduction in the absolute value of the slope of the regulation constraint. From point such as E, holding utility constant and tightening r leads to less output and more waste. Hence, normally the effect of lowering the rate of return is to encourage more waste, since both the income and substitution effects are negative. Output, however, is subject to conflicting income and substitution effects. Referring to locus II in Figure A.3 and assuming that there is no monitoring, as the rate of return is tightened and is lowered from monopoly level to marginal cost, the completely regulated manager consumes additional nonpecuniary benefits equal to the entire difference between monopoly return and marginal cost. Stating the conclusion more sharply, exerting maximum regulatory pressure is successful only in transferring the monopoly rents from the stockholders to the managers in the form of perquisites. Of course, the consumer does not benefit at all. Here, as before, the stockholders have no way of converting managerial waste into profits and capturing it for themselves. In the Jensen-Meckling capital market, the manager is disciplined by stock price reductions of new shares as the owner reduces her share of the firm. No similar mechanism exists as the regulator reduces the allowed rate of return. Any successful extraction of profits on the part of owners at the manager's expense would be subject to regulation and eliminated. It is for these reasons that private owners of utilities have no incentive to discipline managers in response to regulatory action.

141

Appendix

In the absence of monitoring, the regulator is incapable of preventing inefficiency. Inefficiency takes on the form of either monopoly profits or of nonpecuniary waste. In principal, monitoring offers some hope. If, in addition to detecting more total slack, monitoring also raises the fraction of waste that is discovered, the manager is encouraged to substitute output for waste. Waste, however, is discouraged by the substitution effect only, since tightening the feasible region, whether by monitoring or by reducing the allowed return, normally has the unfavorable effect of more waste. In practice, the regulator cannot observe the manager perfectly, and consequently the results are between what can be termed perverse regulation and perfect regulation. The regulator's problem is to find the best mix of instruments, given that he has limited powers of observation. Suppose that the regulator wishes to maximize the public interest as traditionally measured by the sum of consumer and producer surplus, plus the cost of monitoring, dM, where d is the marginal cost of monitoring. The policy instruments are r, the allowed fair rate of return, and M, monitoring of waste. Defining x(r, M) and S(r, M) as the manager's reaction functions to the two instruments, the regulator's problem can be stated as: /P(h)dh - cx(r, M) - S(r, M) -dM

(A. 13a)

while never allowing negative profits R-cx-S^x

(A.13b)

The lagrangian expression is L = |P(h)dh - cx(r, M) - S(r, M) - dM + 0{R[x(r, M)] - cx[r, M - S(r, M)]} (A. 14) The resulting first order conditions for optimum are L =Px - e x S + (R' x - c x ) = 0

(A.15a)

L = PxM - ex S - d + (R' x, - c xN4 - S J = 0

(A. 15b)

It is generally assumed that social welfare at the optimal levels of r and M, as determined by Equations A. 15a and A. 15b represents a global optimum, and that it is in fact better than the alternative of no regulation. An example of an internal social optimum is illustrated in Figure A.4. The regulator chooses the highest social indifference curve from the feasible points on the manager's reaction curve. The figure illustrates the tangency condition for the rate of return choice while holding M constant. A similar diagram could be constructed for the parallel monitoring decision.

142

Appendix

Figure A.4 Regulator's Optimum

The optimum point w suggests that since profits are positive (Px > ex + S, or P - c > S/x), the elasticity of waste with respect to r exceeds that of output with respect to r. The regulator sets r so as to increase output, and in so doing, forces the monopolist to a point where the output response is small. The regulator adjusts the rate of return until the ratio of the two types of unproductive expenses are equal to the corresponding ratio of elasticities: (P-C)x/S=71sr/Tlxr

(A. 16)

The numerator is unproductive payments for output in excess of marginal cost, and the denominator is waste. Monitoring continues until the same ratio of unproductive expenses is equal to the similar ratio of monitoring elasticities, corrected for the real resources absorbed by the regulator's auditing activities.

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Index

Access charge, 94-95, 115, 122 Advisory Committee on Competition in Ontario's Electrification System, 120 Alberta, 123 APIv.AEP, 105 n.4 Australia, 118 Averch-Johnson (A-J) effect, 29, 30, 128 Avoided costs, 88 Benefit-cost statements, 131 Bilateral contracts, 43 Blackouts, 7, 67 Block-rate structure, 87 Bonneville Power Administration (BPA), 83 Bottlenecks, 37 n.4 British Columbia Utilities Commission (BCUC), 122 Bulk power supply competition, 83 Buy-own-operate (BOO), 10 Buy-own-operate-transfer (BOOT), 10

Bypass, 94-95, 102, 112 Canada, 6, 119 Central Electricity Generating Board (CEGB), 35, 40 City franchise, 82 Classifying power stations, 17 Collusive practices, 131 Combined-cycle plant, 18 Common carrier, 77, 94 Common costs, 86 Comparative prices, 6 Competition, 48 Competition Act of 1980, 56 Copper losses, 22 Core losses, 22 Cost allocations, 86 Cost-of-service-indexing method (COSI), 34 Cost performance ratio (CPR), 32 Crew, 30 Customers-owners, 37 n.l

150

Index

Customers per employee, 7 Czamanski task force, 72-73, 78, 79

Frameworks, coordinating, 2 Freedom to contract, 43

Decentralized post-PURPA U.S. system, 13 Declining block rates, 85-86, 88 Deferred DSM expenditures, 97 Demand-side management (DSM), 92, 95,97-99, 103, 122 Developed economies, efficiency concerns, 124 Developing countries, electrification of, 125 Dielectric losses, 22 Director-General for Competition, 56 Distribution companies (DisCos), 94, 97, 98, 99 Distribution system, 20

Generation companies (GenCos), 93 Grid Company of Alberta Inc., 124

Edison, Thomas A., 30, 81-82 Efficiency, 5, 17 Electric generation, 15-19 Electricity Consumers Resources Council (ELCON), 102 Electricity Corporation of New Zealand (ECNZ), 118 Electric (Supply) Act of 1926, 39 Electric (Supply) Act of 1957, 40 Electric (Supply) Act of 1989, 55 Embedded costs, 86 Energy crisis of the 1970s, 11 Energy Policy Act of 1992, 89 Environmental programs, 99 European Union (EU), 108; Directive, 109-110; market, 108-109; members, 108 Excessive market power, 104 Existing property rights, 36 Expense-preference models, 30 Fair Trading Act of 1973, 56 Federal Energy Regulatory Commission (FERC), 32, 88, 92, 100; -mandated conditions, 101; -mandated pricing rules, 89 Federal Power Act (FPA) of 1935, 82 Fogel Committee, 68-69, 71 Fossil fuel plants, 17

Harvard Electricity Policy Group, 96 Hedging contracts, 46 Henderson-Czamanski model, 128 Herfindahl-Hirschmann index, 60 Highway pricing, 35 Historic regulatory compact, 100 Hydroelectric power, 18 Incentive mechanisms, 33-34 Incentive Rate-of-Return Mechanism (IROR), 32 Independent power producers (IPPs), 34,70-71,76-77,80,87-89 Independent system operator (ISO), 91, 93-94, 100-101, 103, 110, 120 Industrial Concession Acts of 1912, 113 Inefficiency, 3, 6; allocative, 3, 4; monopoly profits, 31; nonpecuniary waste, 31; technical, 3 Insull, Samuel, 82 Investor-owned utilities (IOUs), 84 Israel, 6, 41; Concession Ordinance, 64; early economic development, 64-66; isolation, 66; tariffs, 69 Israel Electric Corporation (IEC), 6 3 64, 71-72, 76-77, 79, 80; concession ordinances, 64; tariffs, 68-69 Jensen-Meckling capital market, 31 Joint costs, 86 Kleindorfer, 30 Latin American electricity privatization, 10 Legislative process, 132 Lerner, Abba, 3 Ley de Ordenacion del Sistema Electrico Nacional (LOSEN), 112 Lifeline rates, 1,99, 126 Line-losses, 7, 8, 22 Load curve, 17, 19

151

Index Loss of load probability (LOLP), 45 Managerial labor, 28 Marginal cost (MC), 4 Marginal cost pricing, 88 Marginal social benefits (MSB), 3 Marginal social costs (MSC), 3 Marginal utility (MU), 3 Market-determined prices, 29, 101 Mechanical generators, 15, 17 Mergers, 131 Monitoring, 28 Multinational electric companies, 7 Municipal ownership, 82, 84, 96 Munies, 82, 84, 96 National Governors' Association (NGA), 104 National Grid Company (NGC), 42, 43, 46-47 National Regulatory Research Institute (NRRI), 105 n.4 Natural monopolies, 93 New England Power Pool (NEPOOL), 89,93, 101 New South Wales (NSW) electricity supply, 119 New York City blackout of 1965, 2 New Zealand, 6, 117 Non Fossil Fuel Obligation (NFFO), 49 Nonspinning reserve, 21 Norris-Rayburn bill, 83 North American Free Trade Agreement (NAFTA), 120 Northern Ireland Electricity (NIE), 5 3 54 Norway, 113-117; Market-oriented competitive system, 114; Norwegian Water Resources and Energy Administration, 114; point tariffs, 115; state-owned power grid company, 114; trade, 116 Nuclear power plants, 17 Nuclear waste, 18 OFFER, 42 Ontario Hydro, 120, 122 OPEC-induced oil shortages, 128

Operating and maintenance (O&M) expenses, 69 Order 888, 42, 92, 100-102 Organization of Oil Exporting Countries (OPEC), 11 Palestine Electric Corporation Ltd. See Israel Electric Corporation Perfect labor market, for managers, 30 Perfect regulation, 31 Personal benefits, 3 Perverse regulation, 31 Point tariffs, 115-116 Political framework, 26 Pool input price (pip), 45 Pool output price (pop), 45 Poor (rural and urban) populations, electrification, 125 Postage stamp rate, 122 Post-PURPA IOUs, 89 Power brokers, 115 PowerGen (PG), 42 Power pool, 21-22, 34, 44-46, 77, 8 9 90,93, 118, 124 Pre-Thatcher period, 39-44 Price-cap regulation, 56-57, 69, 78, 111 Privatization, defined, 9 Profit maximization, 28 Profit-maximization framework, 30 Public sector ownership, 7 Public Utility Holding Company Act (PUHCA)of 1935, 82 Public Utilities Regulatory Policies Act (PURPA), 11, 13, 34, 71, 80, 87-89, 129 "Quiet life," 31 Rate-of-return regulation, 29, 78 Red Electrica de Espania (REE), 111 Regional Electricity Companies (RECs), 42, 47, 50, 51,52 Regional transmission tariff (RTG tariff), 90, 91 Region-wide transmission system revenue, 91 Regulators, 28 Regulatory incentives, 32-34, 55, 57, 61

152

Rent-seeking, 129 Retail competition, 92 Retail energy companies (RetailCos), 94 Retail-wheeling, 92 Ross-type mechanism, 33 RPI-X formula, 52, 57 Rural Electrification Act of 1936, 83 Scotland, 53-54 Simultaneous maximum demand (SMD), 21 Spain, 111-112 Spinning reserve, 21 Spot marker contracts, 116 State-owned enterprises (SOEs), 9-12, 63, 108, 118 State-owned monopoly, 6 Stranded costs, 35-36, 48-49, 94-98, 102, 111-122 Subsidies, 6 "Sunshine clause," 77 Supply competition, 44 System marginal price (SMP), 45 System-wide transmission, 91 Takeover bids, 28 Tennessee Valley Authority, 83 Thailand, 7 Thatcher government in Britain, 10 Time-of-use rates, 51 Trading companies, 115

Index

Transmission company (TransCo), 94 Transmission pricing, 35 Transmission rates, 88-91, 122, 124 Transmission system, 92 Twenty-first century thinking, electric industry, 129 UI proposal, 91 United Illuminating Company (UI), 89 United Kingdom, 40, 41; reliability, 61 United States, 6, 41; Army, 83; electric industry, 81; power pools, 44; reforms, 88 Upper limit, 28 Utility-determined quantities, 29 Value of the lost load (VLL), 45 Vardy, Joseph, 70 Vardy commission, 70-73 Vermont proposal, 93, 95, 96, 97, 98, 100, 101 Vermont system, 93 Vertically integrated companies, 127 Vertically integrated pre-PURPA U.S. utilities, 13 Watercourse regulation, 113 Wires business, 126 Wires network, 21 Yom Kippur War (1973), 128

ABOUT THE AUTHOR Daniel Czamanski is Professor of Urban Economics at the Technion-Israel Institute of Technology and member of the Klutznick Center for Urban and Regional Studies. He has also been a faculty member at the Ohio State University and an Institute Fellow in Economics at the National Regulatory Research Institute. As an advisor to two ministers of energy in Israel, he prepared the draft legislation to reform the electricity sector in Israel.