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

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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


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


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


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.


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


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


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


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


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


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


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


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


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


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


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.


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.


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


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


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


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-


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


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


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


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


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-


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.


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


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


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).


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


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


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


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


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


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:


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


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


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


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

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.

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