Public Utilities
Public Utilities Management Challenges for the 21st Century
David E. McNabb, Ph.D. Professor of Business Administration Pacific Lutheran University
Edward Elgar Cheltenham, UK • Northampton, MA, USA
© David E. McNabb, 2005 All rights reserved. No part of this publication may be reproduced, stored in a retrieval system or transmitted in any form or by any means, electronic, mechanical or photocopying, recording, or otherwise without the prior permission of the publisher. Published by Edward Elgar Publishing Limited Glensanda House Montpellier Parade Cheltenham Glos GL50 1UA UK Edward Elgar Publishing, Inc. 136 West Street Suite 202 Northampton Massachusetts 01060 USA
A catalogue record for this book is available from the British Library Library of Congress Cataloging-in-Publication Data McNabb, David E. Public utilities : management challenges for the 21st century / David E. McNabb. p. cm. Includes bibliographical references and index. 1. Public utilities—Management. I. Title. HD2763.M36 2005 363.6⬘068—dc22
2004061454
ISBN 1 84376 873 9 Printed and bound in Great Britain by MPG Books Ltd, Bodmin, Cornwall
Contents vi vii viii ix
List of figures List of tables List of boxes Introduction PART I FUNDAMENTAL ISSUES IN PUBLIC UTILITY MANAGEMENT 1 2 3 4
Public utilities: shaped by challenge and conflict Policy challenges facing public utilities The public utility ethics challenge The public utility regulatory challenge
PART II 5 6 7 8 9 10 11 12
13 14 15 16
PUBLIC UTILITY MANAGEMENT CHALLENGES
Meeting challenges in public utility planning Utility management and leadership challenges The challenges of utility pricing and rate setting The public utility marketing challenge Information challenges for public utility managers Utility finance and accounting challenges Challenges in managing utility human resources Challenges in public utility governance
PART III
3 19 39 54
73 91 109 127 145 163 182 196
PUBLIC UTILITY SYSTEM CHALLENGES
Challenges in the electric energy industry Challenges in the natural gas industry Challenges in the water and wastewater industries Future challenges facing utility industry managers
219 237 252 269 291 313 327 330
Glossary and useful terms References Name Index Subject Index v
Figures 3.1 3.2 10.1 10.2
Major factors influencing moral behavior of workers and managers in public utilities Factors contributing to ethics of public utility management Balance sheet accounts in the NARUC system The flow of accounting information
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44 51 171 179
Tables 7.1 A partial rate schedule for miscellaneous electric services 7.2 Some retail electricity rates in the Western Electric Coordinating Council Region, 2002 7.3 Some 2003 utility rate request outcomes and rates of return 7.4 Peak wholesale and average retail prices in six U.S. cities 10.1 Example comparative balance sheets for a natural gas utility 10.2 Example of a retained earnings account 10.3 Example of a combined income statement for a publicly owned utility 13.1 Fuels used to generate electricity in the U.S. in 2002 and 2010 projections 15.1 U.S. community water systems by ownership type, population served, and annual revenue (1995) 16.1 Projected increases in natural gas use in the U.S., 2004–25 (trillion cubic feet per year)
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113 114 117 122 173 175 178 223 256 281
Boxes 3.1 5.1 5.2 5.3 5.4 5.5 5.6 6.1 7.1 8.1 8.2 9.1 9.2 9.3 9.4 11.1 12.1 12.2 13.1 13.2 14.1 14.2 15.1 15.2 16.1
California takes steps to avert summer power shortages The 2002 Mission Statement of AES Corporation The 2002 Company Profile of Westar Energy The 2002 Company Profile of the CES Company 2002 Company Profile of Artesian Resources Corp Profile of a Public Utility District The environmental policies of Xcel Energy Hodgkinson’s Four Laws of Leadership Consumer perceptions of utility prices Trading activities of Dominion Resources, Inc Marketing in a diversified gas company Integrating communications systems architecture Investment in information technology in a small investorowned utility Utility chief information officers discuss plans and problems Data warehouse problems and safeguards KBC Advanced Technologies’ human resources policies South Jersey Industries: a typical utility holding company Governance in a large regional power cooperative How restructuring brought changes to one integrated utility Cross-border interconnect by a Texas utility CenterPoint Energy: a diversified energy delivery company How El Paso Electric Company manages its gas purchases Supplying water to the citizens of Lacy Veolia Environment of Paris: a water multinational firm Coal makes a comeback
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42 78 79 80 81 81 83 99 124 134 141 149 154 154 155 193 200 207 221 227 239 241 255 263 274
Introduction Public Utilities: Management Challenges for the 21st Century was developed from a base of knowledge gained as a member of citizens’ committees regulating municipal and investor-owned utilities, from experience gained during employment in municipal industrial development, and from academic studies in organizational development. Those experiences brought to light a need for a survey text that would give new advisory committee members, directors, employees, and students an introductory overview of the industry and some of the current issues facing utility management. Like most industries, the public utility sector has devolved into a number of different application fields, including electric energy, natural gas, water, wastewater, telecommunications, and cable television. In some locations, the utility industry sector also includes public transportation, heating oil delivery, public warehousing, and other public services. For each of these fields, a number of texts are available that address specific issues in the specific utility. However, little current written material that covers common industry issues and challenges seemed available. This text was written to help fill this need. It includes issues faced individually and in concert by the electricity and natural gas energy sectors, and the water and wastewater sectors. The management topics addressed in this text evolved from a series of organizational development team projects conducted for public and private, profit and nonprofit organizations. My interest in public utility management challenges began in Orange County, California, where I worked with investor-owned public utility managers and local government officials to promote economic development. That experience led me to research the history and development of the sector for a thesis on arguments between the supporters of public and investor-owned public utilities. The time to continue my interest in public utilities became possible with early retirement from the management faculty of Pacific Lutheran University. After leaving PLU, I was invited to spend nearly three years as a visiting instructor in the graduate public administration program at the Evergreen State College of Olympia, Washington. A number of my students were employed in various aspects of local or state utility administration, including public utilities. Subsequently, I was privileged to spend periods over the course of three years as a visiting professor at the Stockholm ix
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Introduction
School of Economics in Riga, Latvia, where I was able to investigate the way a newly democratic society went about developing local government institutions. Several jointly written papers on portions of that research were presented at public management conferences and published in several journals.
SCOPE OF THE BOOK Two major themes are reflected in this study of management in public utilities. The first theme is associated with the New Public Management (NPM) approach to the managing of public services and the challenges that this concept presents managers in publicly and investor-owned utilities. The fundamental management paradigm shift associated with NPM involves replacing an older bureaucratic approach, which once characterized most of the publicly and investor-owned public service industries, with a new, ‘reformed’ approach constructed from four main building blocks. These building blocks include: (1) limits to civil service autonomy, thereby making government more responsive to political influence; (2) introduction of performance-based management principles and practices from the private sector to improve management efficiency, effectiveness, and accountability; (3) greater transparency in operations, with increased participation by individuals, consumer groups and local communities in the design and delivery of all public services; and (4) widespread deregulation of investor-owned utilities. Each of these plays an important role in public utility management as we embark on this new century. Unlike other industries, the public utility sector of the economy includes both public and investor-owned organizations, some of whom compete with one another. Despite the few victories of public power interests during the years of the Great Depression, more than three-quarters of the U.S. electrical power industry has remained in the private sector. The reverse was true in most of Europe, however, where national, regional, or local governments owned and operated all electric power grids, water systems, telephone, and even radio and television broadcasting. Beginning in the 1970s, however, the European utility industry began to be turned upside down. Privatization of many nationalized utilities and deregulation of the private sector began during the 1980s and 1990s in much of the world, including New Zealand, the United Kingdom, Norway, Sweden, Australia, Canada, Brazil, and Chile, among others. It has taken hold in the United States as well. The privatization and deregulation movements were part of a larger NPM revolution in public administration. The key components of NPM are the sale of many nationalized industries, deregulation of much of the
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once-tightly controlled economic structure of the countries involved, and a reduction in the size and scope of national government in general. It also had a large impact on the way that investor-owned utilities are managed, as the movement came to include the break-up of vertically integrated utilities and interjection of market competition into what had been a closely regulated industry. Although much of the public utility industry remains in the hands of private investors, the concepts that underlie the NPM public sector are relevant to all public service organizations, regardless of their ownership structure. Therefore, discussion of the changes in the fundamental management tasks that NPM has brought about in the public sector is applicable in investor-owned utilities. The second theme is the concept of strategic management and all that it entails. Strategic management is the name given to the set of decisions and actions that result in the formulation and implementation of plans designed to achieve an organization’s objectives. The process involves identifying long-term objectives for the organization, developing strategies for meeting those objectives, and selecting a mix of resources to use in a system of related tasks (tactics). The first two tasks are closely related: the first says what the company does; the second says what the organization is. The strategic approach to management involves a number of related actions that lead managers through a process of identifying strategic opportunities, environmental threats, evaluation of organizational strengths and weaknesses, and developing functional objectives, tactics, and performance measurements and adjustments. The strategic management approach includes environmental analysis, policy analysis, opportunity analysis, mission and vision development, integrated planning programs, and other management activities.
STRUCTURE OF THE BOOK The book is organized into three parts. Part I, Fundamental Issues in Public Utility Management, establishes the framework for subsequent discussions of management practices in public utility organizations. This section includes four chapters that frame the fundamental concepts included in the remainder of the text. Chapter 1, ‘Public utilities: shaped by challenge and conflict,’ introduces the reader to the scale and scope of the public utilities industry. The chapter includes a brief historical review of the growth of the industry in the United States and goes on to suggest a version of how and why the utilities industry developed its special character as a ‘natural monopoly’ committed to servicing the public interest. Chapter 2, ‘Policy challenges facing public utilities,’ presents an overview of the role of public
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policy and traces some of the major utility policy changes that have taken place in the last 100 years. The chapter includes brief introductions to government policy pertaining to electric power, natural gas, and drinking water and wastewater treatment. Chapter 3, ‘The public utility ethics challenge,’ presents a brief introduction to what happens when organizations fail to produce and employees fail to follow standards of ethical behavior. It is followed by an overview of the several bases for ethical behavior among workers and organization leaders. Chapter 4, ‘The public utility regulatory challenge,’ begins with a rationale for utility regulation, and then discusses some of the major regulatory issues in the electric power, natural gas, and water and wastewater industries. The chapter and section concludes with an overview of some conflicting views on utility deregulation and/or reorganization. Part II of the book, Public Utility Management Challenges, contains eight chapters which focus on some of the chief challenges extant today in the management of public utility functions and activities. The section begins with Chapter 5, ‘Meeting challenges in public utility planning.’ This chapter begins with a review of the fundamental concepts that underlie the strategic planning process. In addition to defining strategic planning, the discussion then leads the reader through a brief review of the steps involved in applying strategic planning and how this results in the application of strategic management. The chapter concludes with a discussion on how utilities apply federal government-recommended ‘Integrated resource planning’, a type of strategic planning with particular relevance for utilities. Chapter 6, ‘Utility management and leadership challenges,’ begins with a quick review of some management fundamentals before moving on to discuss issues particularly relevant to utility managers. Chapter 7, ‘The challenges of utility pricing and rate setting,’ covers one of the least understood concepts in utility management: setting prices at the wholesale and retail levels in a mixed regulated and unregulated industry. The material in this chapter is very basic; it introduces readers only to key concepts in ratemaking. Readers wishing to delve deeper into this sub-section of economics are encouraged to seek further explanation in the many economics texts that deal specifically with the rate-making problem. Chapter 8, ‘The public utility marketing challenge,’ might also appropriately be subtitled ‘Demand analysis and management.’ Today, most utilities are less interested in increasing demand for their products than they are in managing existing demand. In this instance, managing demand can mean slowing growth as well as inducing greater consumption. Slowing growth reduces the need to install additional production, to add new distribution capacity, or to locate new sources of supply. It also helps managers in their attempts to level out demand across more supply periods. An important
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part of this process is the forced requirement to develop and adhere to expensive conservation, security, and environmental protection programs that have been mandated by the federal government. Chapter 9, ‘Information challenges for public utility managers,’ deals with information technology, including real-time metering, and other important communications and management information system concepts. Chapter 10, ‘Utility financing and accounting challenges,’ discusses some of the major challenges facing utility managers today as they seek financing for the large investments needed to replace worn out and obsolete systems. Recent bankruptcies of portions of the industry after the crisis that resulted from the implosion of the California reorganization process have raised the cost of capital to more closely reflect the perceived risk associated with utility securities. Chapter 11, ‘Challenges in managing utility human resources,’ focuses on problems utilities face in replacing the many skilled and professional workers who are approaching retirement age; it then includes a discussion of the changing nature of the workforce that is resulting from greater cultural and ethnic diversity in the population of the United States. Chapter 12, the final chapter in this section, covers ‘Challenges in public utility governance.’ This chapter looks at both regulatory and corporate governance and the governance challenges resulting from reorganization of the industry. Part III, Public Utility System Challenges, contains chapters on some of the key challenges facing three specific sectors of the industry, including a look at some of the emerging challenges facing all managers in both the investor-owned and publicly owned segments of this industry. Chapter 13 deals with ‘Challenges in the electric energy industry.’ Chapter 14 covers ‘Challenges in the natural gas industry.’ Chapter 15 focuses on ‘Challenges in the water and wastewater industries.’ Topics addressed in Chapter 16, ‘Future challenges facing utility industry managers,’ include globalization, security, the hiatus of deregulation, and such NPM issues as privatization and outsourcing, and managing the introduction of technology and innovation.
ACKNOWLEDGEMENTS This book could not have been written without the many contributions of authors and researchers whose names do not appear on the cover. Public utilities have been a topic of considerable interest for economists, business managers, and public administrators for more than 100 years. The large body of literature produced over that period and investigated for this study includes works taken from both academic and professional sources. I owe
xiv
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a significant debt of gratitude to the important contributions of all the authors who preceded me in this endeavor. At the same time, however, I wish to make it clear that any errors of either omission or commission are entirely my own. The conclusions presented herein and the choice of topics selected is entirely mine. Nothing in this text should be construed to reflect the opinion of any other writer, living or dead. Research for this text began in earnest during a one-year tour in Europe with the University of Maryland-University College, where I was privileged to teach graduate and undergraduate business and public management courses to members of the U.S. military. I wish to thank my many colleagues in academia for their continued support, advice, and guidance in addressing the many diverse management issues covered in this book. Although many helped, several stand out for the significance of their contributions: Management professors Dr. F. Thomas Sepic, and Dr. ChungSingh Lee, and Professor of Finance Dr. Bruce Finnie. Professor Sepic and I have had a fruitful 15-year period of joint research and publication in the fields of organizational development and organizational culture. Professor Lee is a respected scholar in information technology, innovation, and public policy; his guidance was helpful in a number of situations during the book’s preparation. Professor Finnie willingly shared his years of experience as an economist in the electric power industry. I wish also to extend special thanks to Jean M. Graves, who for many years was an English instructor at Bates Technical College. Ms. Graves provided invaluable assistance in the preparation of the final manuscript. Her professional editorial skills, willingly shared, helped make significant improvements in the text. The following individuals also must be thanked for their kind assistance with this and earlier scholarly activities: Dr. Gundar King, PLU Business School Dean Emeritus; Dr. Thaddeus Barnowe, Interim Dean of the PLU Business School and Professor of Management; Dr. Anders Paazlow, Rector of the Stockholm School of Economics in Riga (Latvia); and Dr. Cheryl S. King and Dr. Larry Geri, both of the Evergreen State College Public Administration faculty. A special thanks is due to Dr. James M. Clapper, Dean of the PLU School of Business, for his support and encouragement for this and other projects. I owe a great debt of gratitude to Mr. Jeffrey Showman, Knowledge Manager, and Lisa Lloyd, Records Center Manager, both of whom are employed at the Washington Utilities and Transportation Commission (WUTC). They provided significant support during my research for the text. In addition, Executive Director Wyla Wood and the staff of the Mason County Public Utility District No. 3 went out of their way to provide all the asked for assistance. Mr. Michael Golat, director of utilities
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for the City of Shelton, Washington, also provided important information and guidance to the author. Finally, I wish to express my gratitude to Mr. Alan Sturmer, Edward Elgar Publishers Acquisitions Editor, for his unwavering support and encouragement during the planning and writing of the text. David E. McNabb, Ph.D. Professor of Business Administration Pacific Lutheran University Tacoma, Washington
PART I
Fundamental issues in public utility management Blackouts, rolling brownouts, sickness and death spread by polluted drinking water, aging infrastructure, more stringent environmental controls, bankruptcies, wholesale and retail competition, increasing diversity, an aging workforce, government mandated restructuring and deregulation: these are just a few of the many management challenges facing the managers and administrators of the public utilities industry. This section introduces the utilities industry, provides a brief historical overview of the evolution of utility systems, and then goes on to address several environmental challenges in somewhat greater depth. Included are discussions of these important environmental constraints: public policy, ethics and responsibility, and the overall regulatory environment.
1.
Public utilities: shaped by challenge and conflict
A paradigm shift is taking place in the way public utilities are managed, regulated, and governed. The bureaucratic model of public administration developed by Max Weber and added to by Woodrow Wilson has come under attack. Traditional bureaucratic administration is giving way to market-driven managerial leadership. The historical method of governments’ regulating utilities as ‘natural monopolies’ is rapidly shifting to deregulation. In many part of the world regulated utilities face an accelerating drive for the economic efficiencies that are expected from free market competition. A large segment of the public sector of the industry has already been replaced by private, investor-owned businesses. However, not all of the changes to the regulatory system have been successful. The collapse of a number of deregulated and privatized utilities, the growing number of brownout and blackouts in the electricity sector, and natural gas and water shortages attest to the difficulties facing utility restructuring. Behind this era of modification in the public service industry is a complex set of forces for change that are driving the shift from the traditional bureaucratic model of administration toward a new, managerial model. This shifting administrative paradigm first appeared in New Zealand. The new way of governing was adopted in the United Kingdom in the 1970s under the leadership of Prime Minister Margaret Thatcher and shortly afterward in the United States by President Ronald Reagan. Over the last two decades of the twentieth century, the old authoritative administrative regulatory system has been replaced by a market-oriented managerial system that is characterized by privatization, application of user fees for public services, public and private sector partnerships, strategic planning, program evaluation and accountability, and a flattening of the administrative hierarchy. This is not the first major paradigm shift in the way business and public utility services function in the western democracies. The first major change began near the start of the last century as laissez-faire economic principles were replaced by federal and state legislative controls. To understand the effect of today’s changes, it is important to quickly review how the utility industry emerged from the nation’s early business system. 3
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PROBLEMS OF EARLY BUSINESS The Europeans who braved the arduous sea journey to settle in North America during the sixteenth, seventeenth, and eighteenth centuries brought with them the cultural traditions that they knew and understood. The profit motive was a driving force behind much of the discovery and development of the colonial world; many of the early colonies were financed explicitly to exploit and profit from commercial opportunities. For the first 200 years of its history, business in the New World flourished under a laissez-faire economic approach, largely untouched by government intervention or guidance. As long as early enterprises remained profitable, colonial governors found it prudent to keep their hand off businesses that operated under their jurisdiction. Even when some measure of control was considered advisable, control remained problematic. The great distances, nearly non-existent colonial infrastructure, and inability to enforce regulations and decrees among the frontier settlements: these all contributed toward making colonial governments more or less powerless to administer all but the most inconsequential of controls over entrepreneurs. The little commercial justice that did exist outside of the few towns and early cities was likely to be vigilante justice. It was not until the late eighteenth century that things began to change. This policy shift began with Britain’s attempts to have the colonies pay a larger share of the cost of governing the colonies, and ended with successful revolution against British rule. A pressing need of the colonies was for the development of transportation infrastructure necessary for the conduct of both domestic and international trade. Under the colonial system, manufactured goods were shipped to the colonies and traded for raw materials and farm products. Public works at that time were generally limited to the construction of frontier palisades and the rough roads needed to supply food and munitions to the small forces left to garrison the crude log fortresses along the forested frontier. These garrisons provided only limited protection against French and Indian forays against isolated farms and small settlements. Individuals or small groups motivated by private gain carried out almost all early infrastructure improvements. Toll roads, ferries, and bridges are examples of such privately developed infrastructure. The great bulk of commerce moved either by mule train over the rough trails through the forests, or by water on small coastal vessels, or riverboats. It was the nearly universally recognized need for better means of transportation that spawned much of the nation’s early collective action on infrastructure development, including canal construction. Eventually this collective action would bring on recognition that a means for controlling and facilitating the flow of commerce among the colonies was also needed. A need was also recognized
Public utilities: shaped by challenge and conflict
5
for some central government involvement in improvements that benefited all the public.
THE SHAPE OF EARLY BUSINESSES Four types of businesses prevailed during the colonial period in North America: small private farms, large cotton or tobacco producing plantations, small country inns, taverns, shops, and branch operations of European trading houses. The most important economic institutions in the colonies were branch operations of joint-stock companies established in the mother country to exploit opportunities in the New World. Homecountry owners or directors made all major decisions in these joint-stock operations. Most enjoyed monopoly positions in their areas of operation. Colonial institutions were established to secure a steady supply of raw materials and agricultural products for manufacturing processes located in Great Britain. Early businesses such as frontier trading posts were established to provide quick profits for investors in Britain. Two examples were the Virginia Company, chartered in 1606, and the Massachusetts Bay Company, chartered in 1629. Chartered proprietary holdings that followed consisted of large tracts of land granted by the King of England to a proprietor as payment for political favors and included provisions for a share of the profits for the Crown. The Hudson’s Bay Colony in Canada is an example. Few free British citizens were eager to immigrate to the colonies as servants or employees during this early proprietary-holdings phase, thereby limiting the number of successful Crown Colonies. However, other forces helped encourage many others to make the long voyage to the new lands; these forces were the drive to better one’s lot in life and the desire for religious freedom. Champions of nonconforming religions helped establish two of the most successful of these colonies: Lord Baltimore’s Maryland Colony, founded in 1634, and William Penn’s Free Society of Traders in Pennsylvania, which was granted a royal charter in 1681. The Maryland colony was to be a haven for British and Irish Catholics, although more Protestants and Catholics eventually immigrated to the colony. Pennsylvania was established as a haven for Europe’s persecuted Quakers. Both colonies offered settlers relatively large tracts of rich farmland free or at low cost, which could be paid for over long periods of time (Morison 1965). The second period in the development of the American business system was characterized by a breakdown of authority in the colonies brought about initially by the Civil War in Great Britain. What commercial policy
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that existed turned inward, and money for colonial investments dried up. The migrants in this period were less interested in carving farms out of the New World wilderness and were more interested in making their fortunes as fast as they could. Much of the migration that occurred at this time was forced. Many of the immigrants at this time were convicted prisoners or slaves. Prisoners might hope for freedom at some time in the future but the slaves were destined for a lifetime of plantation labor. A small number of colonial opportunists included early independent fur traders, operators of frontier trading posts or small coastal traders sailing their own, locally built vessels. Limited access to British manufactured goods during this period resulted in the start of a few early manufacturing operations, including development of small iron smelters using easily collected bog ore (iron ore washed down from higher elevations that collects in clumps in swampy areas). Most of these early manufacturers were small, individual family owned and operated establishments. A new phase in the evolution of the business system in America began in the early 1700s. By this time most settlements along the East Coast had achieved a degree of stability and order, with authority firmly established in the hands of Crown-appointed governors. A solid, legitimate foundation of local merchants had evolved from the ranks of farmers, laborers, and skilled craftsmen who dominated earlier stages of home-grown businesses. In the north, particularly in Massachusetts and Pennsylvania, entrepreneurs were often transplanted merchants from the Mother Country who maintained their strong family and business ties to older established merchant houses in Britain and other parts of Europe. The North American merchant traders of this period collected quantities of the many products produced in the colonies for shipment to Europe, particularly to Britain. Products included furs, fish, timber and other wood products, tobacco, flour, rice, and indigo, among others. The merchants imported manufactured goods such as iron products, textiles (mostly woolens), coffee, tea, paper, sugar, molasses, wine, glass, and earthenware, which were then resold on commission. These merchants depended upon British exporting houses for credit, capital, shipping, and further sale of their goods across Europe and beyond. As the 1700s came to a close, it was obvious to many that some measure needed to be taken to ensure the free flow of goods and people among the various colonies. This need became even more pressing with the fight for independence from Britain. Two early examples of the need for a national policy toward development and maintenance of infrastructure were turnpikes and waterways. Government regulation of public utilities can be said to have evolved from these two vital transportation systems. Regulation began with passage of the Ordinance of 1787 for control and governance of
Public utilities: shaped by challenge and conflict
7
the Northwest Territory, which included present-day Ohio, Indiana, Illinois, Michigan, Wisconsin, and part of Minnesota (Hull and Hull 1967). A key section of the Ordinance established the free and open shipment of goods and people – that is, without any tax or customs duty – by all citizens of the United States on the navigable waters leading to the Mississippi and St. Lawrence rivers. Emergence of a Dual Economy By the last decades of the nineteenth century, a combination of rapid growth, consolidation, and increasing scope in the business system of the United States had resulted in creation of a dual economy. At the top were a relatively small number of large and growing firms. In most major industries, a few large firms operated in an oligopolistic environment, often in trusts led by a single wealthy and powerful individual. Leading industrial growth at that time were three industries: railroads, coal, and iron and steel. At the other end of the spectrum were a large number of small, family owned and operated entrepreneurial enterprises. Three environmental forces had combined to reinforce this shift in the economic structure of the nation. The first was the accelerated shift in the demographic makeup of the nation’s population. Population growth and concentration in cities would eventually make possible the New World’s first truly mass market. The second factor was a consolidation of the major industries in the United States. Consolidation occurred through mergers and the formation of cartels and trusts; these, in turn, made available the huge amounts of capital needed to develop the means of mass production to meet the growing demand for goods and services. The third force was a revolution in transportation, communication, and merchandising. These changes occurred at a time that made possible the mass distribution of goods and services for the new nation-wide mass market. The revolution in transportation was led by growth and development of the nation’s railroads and by application of steam power to inland and ocean-going navigation. The communications revolution began with the telegraph and was reinforced by growth of the railroad. By the turn of the century, telephones had been invented and were in widespread use. Mass merchandising was made possible by the emergence of large retailers with nationwide distribution through an efficient national postal system. It would not be long before government would come to play a very large role in the control and regulation of transportation and communication industries. Growth of the U.S. population and its movement from the farm into cities that were increasingly linked by railroads continued throughout most
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of the nineteenth century. The population of the United States rose from 31 million in 1860 to 63 million in 1890 and to 106 million in 1920. Most of this growth was caused by a wave of immigration from eastern and southern Europe. These immigrants more often than not settled in the nation’s cities and went to work in the new factories and mines. This process started a major shift from the agrarian character of the nation that existed since colonial times toward an industrialized society. In 1860, only 16 percent of Americans lived in towns or cities with a population greater than 5000. That proportion had risen to 33 percent by 1900.
A NEED FOR PUBLIC SERVICES EMERGES As the new cities filled up with new immigrants, a number of important social problems came to the fore. Cities were becoming increasingly dark, dank, and crowded with the poor. Crime and sickness were rampant. Neither sanitation nor running water could be found in the slums housing many of the new Americans. To continue to grow and thrive, cities needed to have sources of safe, economical water, sanitation systems, street and interior lighting, transportation, and reliable, affordable energy. The mechanisms that met these needs at the turn of the century – horses and human muscles, manufactured-gas lighting, and coal and wood-fired steam generators – were not able to keep up with the demands fueled by the new nation’s unprecedented urban growth. City dwellers’ greatest needs at the time were systems for the provision of adequate supplies of clean water, together with a means of dealing with sewage. Inadequate supply of these needs was a major cause of sickness and death in the crowded, unsanitary cities. Well into the 1800s, town dwellers drew their water from shallow wells and discharged their raw sewage into creeks and rivers. The number of civic water systems grew slowly but steadily between 1800 and 1900. At the beginning of the nineteenth century, there were only 16 water systems in cities with a population of 5000 or more; smaller cities still had to make do without running water. Only one of these was municipally owned; private investors owned 15. Twenty-five years later, the total number of water systems had only doubled to 32; five were municipal systems and 27 were private systems. More rapid growth in the number of systems had to wait until after the end of the Civil War. From the 83 systems that existed in 1850, the number grew to a total of 422 in 1875 and to 3179 systems in 1896. The shift to municipal ownership was seen in 1875, when nearly 54 percent were public systems. The proportion declined a small amount in 1896: 1690 or 53.2 percent were public systems (Barnes 1942).
Public utilities: shaped by challenge and conflict
9
Growth in the scale and scope of the utility industry resulted from a revolution in management thinking and decision making that took place after the Civil War (Chandler 1990). This change was brought about first because of the inability of older, informal management practices to cope with the increased size and scope of business. Second, an extensive consolidation of business that began with a wave of mergers unprecedented in scope anywhere in the world to that time took place in the 20 years from 1890 to 1910. And third, a shift took place in the way that managers made decisions. For example, pricing and production decisions that had previously only reacted to what Adam Smith called the ‘invisible hand’ of the market, came to be made internally in order to influence, rather than react to, market demand. The management shift that was taking place in the public service sector at this time began in Europe with reforms proposed by Max Weber (Christensen and Læ´greid 2002). Weber called for the traditional spoils system approach to government employment to be replaced by a cadre of professional civil servants, selected by merit, organized into bureaucracies, and motivated by an ethos of public service. Under the spoils system, the winner of an election quickly replaced many existing office holders with his own appointees. This was the winner’s way of paying off political debts. It was often extremely lucrative for the new appointees – one of President Andrew Jackson’s political supporters managed to steal more than $1 million over ten years after being appointed collector of customs at the Port of New York. The spoils system became a deeply entrenched characteristic of the US political system. Long a tradition in city and state politics in New York, Pennsylvania, and other Northern states, the spoils system was introduced into the federal government by Jackson after his election in 1829. When Jackson began his presidency he replaced 252 out of 612 political appointees with his own people (Morison 1965). The spoils system in the United States was finally replaced by a system of professional public servants, organized according to skill categories spelled out in a rule-based civil service code. These changes in public administration were almost fully in place by the onset of the First World War.
BIRTH OF A PUBLIC UTILITY INDUSTRY The public utility industry was born and grew to a boisterous young adulthood in the last two decades of the nineteenth century and the first ten years of the twentieth century. Fortuitously, the industry was developing at the same time that a professional civil bureaucracy was being trained
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to take on the responsibility of administering the delivery of goods and services for the public good. At the same time, public opinion – fueled by reform organizations like the Grange movement – had shifted in favor of government regulation of many types of private businesses including privately owned utilities. The involvement of the US federal government in controlling perceived abuses of business is often traced to the Supreme Court’s decision in 1877 to uphold efforts by the Illinois State legislature to control prices charged by grain elevators (large storage facilities where grains are stored). During the 1870s a farmer’s benevolent organization, the Patrons of Husbandry (better known as the Grange), became a political force in a number of Midwestern states, where they achieved control of several state legislatures. In this way they were successful in passing a number of laws regulating prices and instituting other controls of private businesses, particularly the railroads and related industries. By 1875, there were more than 22 000 local Grange affiliates, most of which were concentrated in seven central US farm states. Many of the industries affected by these laws believed that what came to be called the Granger Laws were unconstitutional and appealed to the Federal courts for redress; several of the appeals were heard by the US Supreme Court. One of the most important of these Supreme Court cases was the 1877 case of Munn v. Illinois. In 1871, the Illinois legislature passed a law declaring privately owned grain elevators to be public utilities and hence subject to price regulation. Munn and Scott owned an elevator near Chicago. They refused to comply with the new law, saying that it deprived them of private property. They refused to secure a license and post a bond as required and continued to charge rates for grain storage that were higher than allowed by the law. They appealed a lower court decision that upheld the law. In 1877, the US Supreme Court upheld the lower court’s decision, thus establishing the principle that, when private businesses provide public services they are subject to public regulation (Farris and Sampson 1973, p. 23). In his opinion on the Court’s decision, Chief Justice Waite described grain storage as a business that was ‘affected with the public interest.’ It was, therefore, needful of regulation. Before long, other industries would also be determined to be ‘in the public interest,’ and brought under federal or state regulation. The seeds of the regulation idea were planted many years earlier than the 1877 landmark Supreme Court case, however. One of the earliest United States applications of a ruling in the public interest can be found in provisions in the Ordinance of 1787, which mandated free navigation on the nation’s waterways (Hull and Hull 1967). But far earlier than this, municipal provision and distribution of water for human consumption was a feature of the theocratic city states that helped to create civilization in the lands of
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Mesopotamia, Egypt, and the Indus Valley on the Indian sub-continent. A system of aqueducts for long-distance transmission and hand-crafted lead pipes for municipal distribution water was also one of the major distinguishing characteristics of the Roman Empire. In North America, the first water supply system was built in Boston in 1654. It consisted of a simple reservoir where water gathered from five springs was stored for public use. A more complex system consisting of a wooden pump, reservoir, and pipes made from hollowed-out logs was established at Bethlehem, Pennsylvania, in 1762. Providence, Rhode Island, developed its system in 1772. These three were the first recorded water supply systems in North America. The production and distribution of manufactured gas began early in the nineteenth century, although its high price kept its use limited primarily for street and public place lighting until after competition from new electric lights and the 1876 invention of a new production process forced prices down. The first commercial plant was built in Baltimore, Maryland, in 1816. Other coal gas plants were opened in Boston in 1822, New York in 1823, Brooklyn in 1835, and Bristol, Rhode Island, and New Orleans shortly afterward. Natural gas was first used for industrial purposes in 1870, when the Bloomfield and Rochester Natural Gas Light Company brought gas in wooden pipes to Rochester, New York. The use of electric power for lighting purposes was first put to a test in 1858 when an arc lamp was installed in a lighthouse near Dover, England. Arc lights were far brighter than gas streetlights. It was not long before civic leaders saw the advantages of using arc lights to illuminate their alleys and streets, and contracts were negotiated with new entrepreneurs to rig and operate municipal lighting systems. The first manufacturers of electrical equipment in the United States began by constructing arc light equipment; they also formed the companies that operated the new systems. Soon, small generators located in storefront power stations generated power for municipal streetlight systems. Private companies were granted licenses to string power lines on poles installed on the public right of way; this became the standard means of distributing power within municipalities (Bryant and Dethloff 1990). Shaping the Public Utilities Industry The term ‘public utility’ describes the collection of specific services provided by public and private organizations and identifies the institutions that make up the industry. The products or services provided by the public utility industry include electrical energy, natural gas, water, sanitation, waste disposal, communications, public rail and bus transportation, and
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certain types of storage facilities, including public warehouses, and grain elevators, among others. Regardless of their form of ownership, to be regarded as a public utility the entities providing the service must be seen as organizations that are ‘affected with a public interest,’ as identified by Justice Waite in 1877 (Farris and Sampson 1973). Public utilities provide essential services needed by every individual and every other institution in a society. The organizations operating within the industry have the responsibility for seeing that their services are available when and where the public desires them. Collectively, the set of services are referred to as the ‘social capital’ of a society. Without them, there can be no economic development in the society. Yale economist Irston Barnes suggested the following definition for public utilities: Those industries are public utilities which are required to render service at reasonable and nondiscriminatory prices to all who apply for it. The measure of regulation thought necessary to insure universal service at reasonable prices will differ widely from one industry to another, but it characteristically begins with prescribing standards of service and price. (Barnes 1942, p. 1)
Thus, the term ‘public utilities’ describes a large group of economic organizations that exist to locate, produce or collect, transmit, distribute and/or process and store, a variety of products and services that are vital to modern life. These products and services are ubiquitous. They include the electricity that lights our workspaces and powers computers, appliances, and motors in offices, stores, factories, and homes. These services also include the natural gas we use to heat our homes and cook our meals. Natural gas is also an important raw material in many industrial processes. Public utilities also deliver the water we drink and perform the treatment and disposal of our wastewater and household and commercial waste. Also considered public utilities are the organizations that collect, process, and store our solid and liquid waste, including toxic materials and chemicals. Although often forgotten, many of the operations that provide one or more aspects of transportation and/or storage are also public utilities. It was government regulation of this class of activity – transportation of the public waterways and railroads – that were among the first public services included in the utility industry. Are Utilities ‘Different?’ Utilities differ from other industries for a number of reasons (Glaeser 1957; Farris and Sampson 1973). First, unlike other types of businesses, utilities are legally required to serve all customers in their market area without discrimination; they are limited in this requirement only by their capacity, and may be required to construct additional capacity if demand warrants.
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Second, they are generally neither exclusively profit or nonprofit; a mix of both types of organizations exist, often side-by-side, functioning in the same chain of production or collection and distribution or processing. Third, utilities’ income often includes a mix of earnings from rates charged to their customers, stocks and bonds, and/or taxes. Taxes may be applied in a variety of different ways. For example, the allocations (payments) to the utility may come from a general fund, as in the case of large, publicly owned hydroelectric projects, or in the form of special assessments (one-time, single purpose tax levies) placed upon property owners who benefit from the utility, as in the case of sewer installation charges to property owners who may be served by the line. Fourth, utilities are economic organizations. This is because there is an economic cost to produce and a price for supply of the products, regardless of what form of ownership or governance that characterizes the organization involved in the industry. Fifth, utilities often practice legally sanctioned price discrimination. Utilities are supposed to provide a common benefit to each class of users, but users do not always enjoy equal benefit from the products of the utility. Homeowners are often charged a higher rate for the service than are industrial users, for example. This is often seen as an unfair subsidy from some ratepayers and/or general taxpayers to organizations such as businesses. This discrepancy has long been a source of bitter debate and controversy. Despite this legally sanctioned price discrimination, prices charged by utilities to all their customers must be seen as ‘reasonable’ by regulators and the general public. Sixth, prices for the product or service often do not reflect supply and demand market forces. Rather, prices for many public utilities are set as more or less arbitrary mandates by governmental regulatory bodies after a series of public hearings and supplier justification. In the case of publicly owned utilities, prices are often kept artificially low for political purposes and do not take into consideration the true cost of the service. True costs would give greater consideration to depreciation and the cost to maintain emergency reserves which are mandated by regulatory agencies. With investor-owned utilities, commissions weigh all the cost data provided by the firm to justify their rates. In addition, regulated utilities are allowed to add a legislatively established minimum rate of return to the accepted cost of their operations.
NATURAL OR ARTIFICIAL MONOPOLIES? A fundamental economic principle that is most often pointed to as the key factor that differentiates utilities from all other forms of economic
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organizations is that of a ‘natural monopoly.’ In economics, two types of monopolies can exist: natural and artificial. Natural monopolies occur when a single firm is able to supply a market at a cost and price far lower than would be possible if several firms served the market. This advantage is typically brought about through economies of scale, although other factors including patents and site limitations, also contribute. Site limitations refer to the limited number of locations suitable for hydroelectric dams, reservoirs, gas and wind turbines, suitable places for solid waste disposal, or where natural gas can be found and/or stored. The site limitations problem is sometimes referred to as the ‘not in my back yard’ (NIMBY) phenomenon. Citizens who want utility products when and where they want it agree that new facilities must be constructed – just so long as they are not built near where they live or play. It means pushing the onus onto the shoulders of others. Artificial monopolies, on the other hand, occur because of legal barriers to entry of competitors. The most common example seen today is the exclusive franchise granted to one or a few utilities by municipalities. In Seattle, Washington, for example, solid waste collection franchises for operating in distinct areas of the city are awarded to privately owned firms that submit the lowest bid for the service. Transfer stations and disposal sites, on the other hand, may be owned and operated by the county, or jointly owned by cities and the county. The franchise to construct and operate a cable television system in a community is also usually awarded to a single firm. History of the ‘Natural Monopoly’ Concept The concept of utilities being a natural monopoly came into general use during the Progressive Era reform movement, when the federal government began its first experiments with ways to control the perceived excesses of the very large and growing businesses, cartels, trusts, and early utilities (Helgesson 1999). The American economist Richard T. Ely is credited with being the first to use the term. In his Monopolies and Trusts (1910), Ely defined natural monopolies as businesses that functioned in situations where monopolies not only occurred naturally, inevitably, and were also socially desirable – provided that they were controlled by public regulation or public ownership. In summary, then: The concept of natural monopoly emerged in the U.S. and by 1910 had acquired a place within American economics. It has sprung out of discussions on how the law should respond to large-scale business, public utilities, and monopolies and against the backdrop of an antitrust legislation and local governmental attempts to foster competition among franchised utilities. (Helgesson 1999, p. 121)
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Economists, politicians, and reformer groups were willing to accept the idea that public utilities might serve the public better if they were exempt from antitrust laws only on the condition that they retained the right to keep the monopoly organizations – public and private – on a tight regulatory leash. The tightest form of regulation has always been, of course, public ownership. Although popular in some states for a short time, this idea never gained full sway in American politics. Business lobbies, existing cartels, and the rapidly growing industrial and commercial sector found the idea of public ownership an anathema. However, there was enough support in many parts of the country – particularly the middle and far western states – for public ownership of utilities to gain a solid foundation. The public ownership movement received a further incentive when many investor-owned utility trusts collapsed with the 1929 stock market crash. The result of that collapse was passage of the most far-reaching regulatory legislation to that time, the Public Utilities Holding Company Act of 1935 (PUHCA). This important law and its impact on the industry cannot be overestimated. It was enacted during the Great Depression after the pyramided financial structure of large holding companies collapsed with the stock market crash in October of 1929. The ramifications of this legislation will be discussed in some detail in a later chapter.
A NEW UTILITY MANAGEMENT PARADIGM Federal and local government power sharing in utility regulation issues has been greatly influenced by a larger collection of changes in governance and regulation reform. The public sector reform movement that began in Great Britain in the late 1970s and 1980s under a Conservative government led by Margaret Thatcher has continued without abatement under Labour Party leadership (Hughes 2003). The utility reform movement was founded on four main components: (1) limits to civil service autonomy to make government more responsive to political influence; (2) introduction of performance-based private sector management principles and practices to improve operational efficiency, effectiveness, and accountability; (3) greater transparency in operations, with increased participation by individuals, consumer groups, and local communities in the design and delivery of all public services; and (4) widespread deregulation of investor-owned utilities. Collectively, these four forces are the foundation stones of what is now referred to as the ‘new public management’ (NPM); they are as relevant for the management of investor-owned utilities as they are to utilities operating in the public sector.
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Many European governments, including Sweden, Italy, France, and Germany, among others, have adopted elements of NPM. Other Western nations, such as New Zealand, Canada, Brazil, and Australia, have also implemented NPM policies. The nations that have adopted NPM have done so with a number of similar purposes; these include the reduction of public spending and reduced public employment, reduction of deficits and debt service, meeting a perceived need to modernize and improve the management of government services, and bringing about a turnaround in the global trend of citizens’ distrust in government. Organizations such as the World Bank and the EU are encouraging their lesser developed client states to adopt NPM policies designed to shift public sector operations from their traditional hierarchical, rule-based, process-oriented, bureaucratic structures toward a flatter, performancebased, organizational model in which public managers are willing to take risks, including contracting with private industry for the provision of public utility services. In addition, the public service deliverers – public and private – are dealing with demands to do more with less, while at the same time continuing to provide quality services. The global payoff sought for NPM is development of ethical, motivated, public servants trained in the skills of risk-taking, public–private sector partnerships, management of scare resources, strategic planning, and continuous learning required by a global economy. The ultimate promise held for NPM is a revitalized, modern, public service and utility governance system that is responsible and responsive to the needs of all stakeholders.
SUMMARY The term ‘public utility’ is used to describe a variety of publicly and investor-owned organizations that provide certain specific essential services to residential consumers, industrial and commercial customers, and government organizations. U.S. Supreme Court decisions dealing with the services provided by utilities have resulted in those services to be ‘affected with the public interest,’ and therefore deserving of government regulation. Public utilities differ from other business organizations in at least six ways. (1) Utilities are legally required to serve all customers in their market area without discrimination; (2) they are generally neither exclusively profit or nonprofit; a mix of both types of organizations exist, often side-by-side; (3) utility income often includes a mix of earnings from rates charged to customers, stocks and bonds, and/or taxes; (4) utilities are economic organizations because there is a cost to produce and a price for supply of the products, regardless of what form of ownership or governance that
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characterizes the organization involved in the industry; (5) utilities often practice legally sanctioned price discrimination; and (6) prices for the utility’s product or service often do not reflect supply and demand market forces. Utilities are required to provide a common benefit to each class of users, but users do not always enjoy equal benefit from the products of the utility; homeowners are often charged a higher rate for the service than are industrial users, for example. Despite this legally sanctioned price discrimination, prices charged by utilities to all their customers must be seen as ‘reasonable’ by regulators and the general public. In the case of publicly owned utilities, prices are often kept artificially low for political purposes and do not take into consideration the true cost of the service. With investor-owned utilities, public commissions weigh all the cost data provided by the firm to justify their rates. Regulated utilities are allowed to add a legislatively established minimum rate of return to the accepted cost of their operations. A fundamental economic principle that differentiates utilities from all other forms of economic organizations is that of the natural monopoly. In economics, two types of monopolies can exist: natural and artificial. Natural monopolies occur when a single firm is able to supply a market at a cost and price far lower than would be possible if several firms served the market. The concept of utilities being a natural monopoly came into general use during the Progressive Era reform movement, when the federal government began its first experiments with ways to control the perceived excesses of the very large and growing businesses, cartels, trusts, and early utilities. The utility reform movement includes four main components: (1) limits to civil service autonomy to make government more responsive to political influence; (2) introduction of performance-based management principles and practices to improve operational efficiency, effectiveness, and accountability; (3) greater transparency in operations, with increased public participation by individuals; and (4) widespread deregulation. Collectively, these four forces constitute the basis of the ‘new public management’, and are having an impact upon managers in investor-owned utilities as well as publicly owned utilities.
ADDITIONAL READING Chandler, Alfred O. Jr. (1994), Scale and Scope: The Dynamics of Industrial Capitalism, Cambridge, MA: Harvard University Press. Colburn, David R. and George E. Pozzetta, (eds), (1983), Reform and Reformers in the Progressive Era, Westport, CT: Greenwood Press.
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Ely, Richard T. (1910), Monopolies and Trusts, New York: Macmillan. Glaeser, Martin G. (1957), Public Utilities in American Capitalism, New York: Macmillan. Morison, Samuel Eliot (1965), The Oxford History of the American People, New York: Oxford University Press.
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Policy challenges facing public utilities
The range of the decision alternatives available to public utility managers is framed by the policies that exist at the time the decisions must be made. Public policy has been defined as ‘an intentional course of action followed by a government institution or official for resolving an issue of public concern’ (Cochran et al. 1996, p. 1). Two levels of policy guide public utility managers in their everyday organizational activities: internal and external. Internal policy includes the normal levels of organizational and management policies and procedures that shape the business enterprise. The vision of senior management and board of directors, the organization’s mission, its resources, and the existing organizational climate and culture form internal policy. External policy is a reflection of the environment that shapes and constraints the range of choices from which management policy may be selected. External policy is primarily formed by the influences resulting from the political and public-attitude environment of the period. Examples included tax policy, investment policy, antitrust policy, and the like. Public policy is not a static concept. Rather, the changing attitudes, intentions, and actions of governments and citizens that affect society or a particular segment of a society continuously shape and modify public policy. There are many types of public policies, examples include a nation’s industrial, education, welfare, public safety, environmental, energy, water policies, and the like. Public policy also shapes the types of laws passed by federal, state, and local governments. It also provides a framework for the rules and regulations developed by the government agencies charged with implementing the laws – as well as the court decisions that often follow implementation. The study of policy at all levels is called policy analysis. Public policy is greatly influenced by public opinion. For example, the early stages of the development of public utilities coincided with a strong movement for public control of all public services and natural resources. At the time, public policy was sympathetic to the idea of government ownership of public utilities. Negative public attitudes toward business faded after a wave of Progressive Era reforms, resulting in a fading away of public policy on utility ownership issues. Public policy also influences the amount 19
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and shape of regulatory content and procedures, siting decisions, and utility taxation, among other public service operations. Organizational or corporate policy, on the other hand, refers to the operating guidelines that frame the organization’s mission and fundamental operations. Examples include governance policies, the choice of industry within which the organization operates, debt versus equity financing preferences, and internal or external growth policies, among others. This level of policy is shaped by the actions of the organization’s directors and by chief executive officer attitudes and preferences. Organizational policy is typically made manifest in the stated vision of the leader and the mission of the organization. The mission of the organization is often developed in a bottom-up process, during which all organizational agents are encouraged to participate. Management policy refers to the specific rules, regulations, procedures, and practices that guide managers and workers in their interpersonal and interorganizational actions; examples include an organization’s policies on hiring and promotion, negotiations with labor unions, and discrimination and harassment policies, among others. Challenges When Management Policies Conflict Because policy exists at more than one level in organizations, managers often face difficulties in making decisions when the guiding policies conflict. Advocates of varying policies at all levels often compete with one another for acceptance and adoption. For example, four different policies for dealing with problems of residential nonpayment of utility bills have been identified (Hyman et al. 2001). The traditional policy – the collections model – has been the market approach of ‘no pay, no service.’ Utility companies that follow this collections model approach use overdue notices, threats of termination, and eventual shutoffs to deal with customers who do not pay their bills. A second public policy approach, called the amortization model, is based on the assumption that nonpayment problems exist because of some prior social circumstance. This model permits utilities to use due process procedures for notice and termination. There is no requirement for payment assistance to customers, and regulatory agencies permit service shutoff under conditions of nonpayment. The transfer payment/financial aid model, a third policy approach, is based on a social theory that public utility services are necessities of life and, therefore, their provision should not be based solely on the customer’s ability to pay for the service. Rather, all citizens are considered to have a fundamental right to at least a basic level of utility services regardless of their
Policy challenges facing public utilities
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income. Under this approach, a mix of government, nonprofit organization, and private donations may be used to provide the supplemental income needed to pay for minimal service to needy customers. Utilities themselves are usually not required to underwrite the full cost of this service. This model also leads to conservation of resources through its promotion of reduced or limited consumption of utility services. Hyman, et al. identified a fourth policy approach: the physical environment model. This approach relies on weatherization, conservation, and use-reduction, together with efforts by the utility to lower its costs. This combined approach is employed with the objective of making bills more affordable. The problem for utility managers is that any one of these models may exist at any time in a given service area. Moreover, an existing policy might change overnight with election of a new board or appointment of commissioners with different political and economic biases. Utilities that serve customers in several different regions may find themselves forced to operate under more than one model.
THE IMPORTANCE OF PUBLIC POLICY Clearly, awareness and understanding of public policy is particularly important in organizations engaged in providing utility products or services. Because of their critical importance to society, public utilities typically are subjected to more public scrutiny than other economic activities, with the possible exception of the production of arms and weapons of mass destruction. The open conduct of this public scrutiny is incorporated in the development and exercise of public policy. This chapter focuses on public policy and the overt actions taken by governments that are manifestations of the public policy in effect at the time of the action. The results of public policy on utilities is seen in the character of the laws enacted, regulatory actions taken, court decisions handed down, and the behaviors and attitudes expressed by legislatures and the public on utility operations and issues. It is important to keep in mind that public policies seldom if ever remain permanent; they are always subject to change. Policy changes often occur as a result of some catastrophic event, such as the California energy crisis in the winter of 2000–2001, the Northeast US and Canada blackouts of 1966 and 2003, and the stock market crash in October of 1929 and the Great Depression that followed. The wave of deregulation and mandated restructuring of portions of the utility industry that characterized the last two decades of the twentieth century are examples of reversals in public policy occasioned by external
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events. The critical events in the 1970s were the disruptions of supply of Middle Eastern oil and the quadrupling of the price of crude oil. An energy policy with the aim of reducing the nation’s dependence upon foreign oil supplies was established as a result of those shocks to the economic system. Changing Public Utility Policy Public policy toward utilities has undergone many changes over the 200-plus years of U.S. history. Formation of a federal policy toward utilities was not an important issue until the closing years of the nineteenth century. During the years between the Civil War and the end of the 1800s, America drifted steadily away from its agricultural foundations toward the urbanized industrial nation it would be by the start of the twentieth century. During those transition years the economy of the young nation came to be controlled to a large degree by a few large industrial, transportation, and financial giants (Chandler and Tedlow 1985). Among these giants were segments of what was to become the energy supply portion of the utility industry. From its beginnings in the 1880s until the end of the century, the utility industry received little public attention. Governments and the courts adopted the opinion that utilities were natural monopolies that provided essential public services. As long as the services continued unabated and remained generally affordable, government tended to follow the same hands-off policy it followed with all businesses. This was a time of city building across America, and city growth required an ample supply of reliable energy, water, and sanitation. The leading industries driving the economy in the last half of the nineteenth century were railroads, iron and steel, and coal. Unbridled capitalism was the law of the land (Parrington 1963). By 1900 a dual economy had evolved in the United States, dominated by big business at the center with small businesses existing at the periphery. The power held by the leaders of these giant industries was phenomenal. For example, in 1883 it was the nation’s railroads that established the four time zones in the country as a way of standardizing their schedules. The federal government simply acquiesced in the decision, as it would again three years later when railroad managers got together to agree on a standard-gauge track. Eventually, however, some actions of railroads and the financial houses behind them were considered harmful to the overall economy of the nation and required government intervention and control. Based on court opinions that railroads and associated services such as grain elevators were ‘affected with a public interest,’ the federal government endorsed early state regulatory
Policy challenges facing public utilities
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activities. Railroads were the first industry to be regulated by both state and federal governments. The first wave of trust forming in traditional public utility industries – electricity, manufactured and natural gas, water and sanitation, and telecommunications – began in 1866 when the nation’s three leading telegraph companies merged to form Western Union. Telephones, manufactured gas, oil, and the electricity industries followed similar patterns a few years later. The early entrepreneurs in these fields formed businesses to capitalize on their inventions and discoveries. For example, Charles F. Brush, inventor of the arc-light system, formed the Brush Electric Company in the 1870s. Elihu Thomson and E.H. Houston, high school science teachers, developed improvements on the Brush system and formed the Thomson-Houston Electric Company in 1883 to manufacture electrical equipment. The Thomson-Houston Company soon absorbed many smaller manufacturers and quickly dominated their industry. Thomas Edison, inventor of the incandescent electric light bulb in 1879, acquired a half-million dollars in investment capital and formed the Edison Lamp Company to make and sell light bulbs and the Edison Electric Light Company to install generating and lighting systems. In 1892 the two Edison firms merged to become Edison General Electric. The Edison Company opened a steam electricity generating plant in New York City in 1882, supplying direct current to light streets, businesses, and a few residential customers. Thomson-Houston eventually merged with Edison General Electric in 1892. In 1889, Edison withdrew from the company, and his name was dropped from the company. National, state, and local governments were eventually forced by unbridled growth and technical problems to develop and implement standard policies toward utilities. For electricity, the major problem was that electricity cannot efficiently be stored; generating plants must be constructed with at least 15 percent greater capacity than needed. In the industry’s early years, Edison’s direct current systems competed with the George Westinghouse alternating current system. Manufactured gas was so expensive that only businesses, municipalities, and a few wealthy private citizens could afford it. Very few pipelines existed to move natural gas from where it was found to where it was needed. Until safe supplies could be secured for water systems, water pumped from shallow wells often spread disease. Eventually, civic leaders and reformers forced the federal government, state legislatures, and city councils to recognize their responsibility for provision of safe, secure, stable supplies of utility services. Public utility policy became one of the governments’ chief concerns thereafter.
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FORGING A PUBLIC UTILITY POLICY The initial government policy toward public utilities took shape within the broader framework of a shift in governments’ attitudes toward business in general that occurred in the last decades of the nineteenth century. Steps taken in a few states to regulate some activities of railroads forced the federal government to examine its traditional laissez-faire policy toward business. State legislatures passed laws aimed at redressing perceived issues of restraint of trade, unfair and discriminatory pricing, and the anticompetition activities of trusts. Collectively, these and similar policy changes became incorporated under the label of Progressive Era reforms. They resulted in passage in the states in the upper Midwest of the Granger Laws, named after the sponsoring organization, the National Grange of the Patrons of Husbandry. The laws created state commissions to regulate railroad pricing and end discriminatory business practices (Bryant and Dethloff 1990). The U.S. Supreme Court in the 1877 Munn v. Illinois case subsequently upheld the early state laws. However, by 1886 the power of the states to regulate railroads had been severely curtailed by appeals and by subsequent court decisions. In 1887, the federal government responded to public demands for additional regulation with passage of the Interstate Commerce Act, which established the Interstate Commerce Commission (ICC). The ICC was given the responsibility for regulating the rail system. Developers of early privately financed railroads and utility services were enthusiastically courted by civic leaders, many of whom discovered that essential services also provided a way of personal enrichment. Franchises were often sold to the highest bidder, while kickbacks, payoffs, and bribes were considered a normal cost of doing business. Private citizens had little or no say in the design and construction of network systems. Based on the territory where they were located, customers were told which water, gas, or electricity organization would provide their service, and how much they would have to pay for the service. The establishment of utility services in the nation took three major forms of ownership: private (later called ‘investor-owned’), public (typically municipal), and cooperative. Municipal ownership was the path followed for most water and sanitation services, while manufactured and natural gas systems, telecommunications systems, and electrical energy networks, including traction and street lighting, tended to be established by private individuals or corporations, although in some cities, particularly in the West and upper Middle West, municipal ownership was the norm for all utilities. The third form of organization – cooperative ownership – occurred in small markets, where little profit potential existed to attract commercial interests,
Policy challenges facing public utilities
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and local governments lacked the financial strength or size to warrant municipal ownership. Cooperatives still exist, but mostly for small water and sanitation systems. Decisions were made by utility company directors and managers meeting in secret on such issues as: (1) the form of ownership (holding company or subsidiary); (2) the amount, type, and timing for the sale of securities; (3) on how the service was produced (i.e., should it be self-produced or bought for re-sale); (4) whether new facilities would be constructed and when; (5) if new capacity was needed, where it should be located; (6) the type and location of new transmission lines, pipelines, and distribution network facilities; and (7) how much should be charged to each class of customer. Little or no competition existed because policymakers believed that it would be inefficient to build overlapping systems within the same service territories. There were no state public utility commissions and no public hearings to provide oversight services. According to Federal Reserve Bank economist Richard Mattoon (2002), there were good reasons for maintaining this structure. Utilities in general have always been a capital-intensive industry. Large sums are required for prospecting, drilling, pumping, and storing natural gas; for constructing reservoirs, water treatment plants, aqueducts and pipelines; and for building power plants, transmission lines, street traction and lighting systems. Proper maintenance of extensive distribution networks once they are up and running is also costly. Utility infrastructure is expensive and requires long-lived investments. In order to meet their mandated requirements for provision of service when and where it is required in their operating areas, utilities need to be assured that they would always be able to amortize their large, long-term investments. Electric Power Policy Utilities grew rapidly during the first quarter of the twentieth century. Fueled by floods of low-wage immigrants from Europe, the nation’s industries became world leaders during this period. Industry required uninterrupted energy supplies and raw materials; workers required reliable supplies of utility services, including light, water, and transportation. Utilities grew to meet these demands. Government policy response to the demands for uninterrupted service at affordable prices was to recognize the monopoly status of utility companies, assign them well-defined geographic service territories, and guarantee a reasonable return on their investments. However, because of the potential for abuses inherent in monopolies, the utility companies were eventually subjected to rigorous regulation so as to prevent the exercise of
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monopoly pricing power. The same rationale was eventually applied to all network industries, including water, manufactured and natural gas, and telecommunications. For the most part, this led to a favorable regulatory environment in which utilities were granted monopoly status in return for a pricing structure based on rates that were ‘just and reasonable’. Prices agreed upon reflected the utilities’ cost of production and delivery, with provision for a fair rate of return on invested assets (Mattoon 2002). A shift in public policy toward utilities occurred after the stock market crash of 1929 and the economic depression that followed. One of the victims of the collapse was the Chicago-based holding company empire of electricity and gas utilities put together by Samuel Insull. Insull had earlier strongly supported state regulation of utilities as natural monopolies. At its peak, the Insull utility holding company empire controlled a collection of utility operating and service companies with something like 600 000 investors and 500 000 bondholders. By 1930, his companies had a net worth of more than $3 billion and served customers in 5000 towns in 32 states. The empire collapsed in 1932, bringing financial ruin to thousands of investors. The Public Utility Holding Company Act (PUHCA) enacted in 1935 effectively ended the utility holding company, and brought the federal government into greater regulatory control of the utility industry. During the next decade, government increased its level of control over businesses of all types; it played a particularly important role in the utility industry in this period. Under President Franklin Roosevelt, the federal government became heavily involved in the utility industry, developing huge utility projects and networks, including the Tennessee Valley Authority (TVA) and the Bonneville Power Authority (BPA). These were established as government corporations rather than government agencies. Passage of the Rural Electrification Act in 1936 brought power to distant farms, villages, and small towns across the country; from less than 10 percent in 1935, farms with electricity increased to nearly 94 percent in 1955 (Farris and Sampson 1973). Natural Gas Policy The first major act regulating natural gas appeared several years before the United States’ entry into World War II. The 1938 National Gas Act (NGA) created the Federal Power Commission (FPC) in order to regulate natural gas pipelines, although the price of gas at the wellhead was left unregulated. Economic growth after the war resulted in demand for gas outpacing pipeline capacity, which, in turn, saw excessive retail price volatility and shortages of gas through most of the late 1940s and 1950s. The FPC refused to establish
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price caps, believing that it did not have the power to participate in pricing decisions. Public demands to ease the price and supply problems resulted in a 1954 Supreme Court decision (Phillips Petroleum v. Wisconsin, 347 U.S. 672) that the NGA could be used to regulate pipelines and wellhead prices of gas. The decision solved price problems, but did nothing to resolve supply problems. Attempting to improve the reliability of gas supplies, the Phillips decision resulted in FERC regulation of all purchases from natural gas producers. The initial result was a rash of administrative difficulties and price distortions that lasted for the next two decades and eventually resulted in acute gas shortages. The Natural Gas Policy Act of 1978 (NGPA) was an attempt to solve these problems. However, regulatory reform was initiated only in stages, which resulted in some gas supplies deregulated and others still under federal price controls. The industry responded with ‘take-or-pay’ contracts which resulted in over $20 billion in contract liabilities for gas pipeline firms that were obligated to pay for but were unable to sell to distributors or other customers at prices that reflected their costs (Showman 2004). A New Policy Shift Another major policy shift toward the utility industry began in the 1970s, with the natural gas industry one of the first utilities to be affected by the new policy. The FPC was replaced when passage of the 1978 Natural Gas Policy Act established a new regulatory body, the Federal Energy Regulatory Commission (FERC). Natural gas wellhead gas prices were deregulated when powers allotted to the NGPA reversed the 1954 Phillips decision. As a result, gas production increased dramatically, prices dropped, and by 1985, the decades-long shortage was replaced by a surplus of natural gas. A second piece of legislation passed in 1978 that affected the natural gas industry was the Outer Continental Shelf Lands Act (OCSLA). This law opened up gas pipeline operations to competition by requiring that pipelines provide open, non-discriminatory access to all shippers, regardless of whether they held any ownership in the pipeline. The trend toward open access of pipelines was extended in 1985 with release of FERC Order 436, which required pipelines to provide open access to transit of gas produced by other firms. It unbundled natural gas supply from gas transportation by allowing gas buyers to negotiate prices directly with producers and then contract separately with a pipeline company for shipment of the gas (Platts Global Energy 2004). FERC Order 500 issued in 1987 confirmed take-or-pay contracts between suppliers and customers. Take-or-pay contracts were now seen as providing long-term stability for both parties by requiring the buyer to pay some portion of the cost even if gas is not accepted. As a result of these developments, gas
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marketing firms were established. Often without ties to any gas company, marketing firms provided an intermediary service between gas buyers and other industry segments. The final natural gas policy statement to come out of the 1980s was the Natural Gas Wellhead Decontrol Act of 1989. This act resulted in a phasing out of the regulation of all wellhead prices; it required that all price controls be eliminated by January 1 of 1993. Gas prices were from then on to be freely set in the market. Two major policy developments took place in the early 1990s. The first was the 1991 Mega-Notice of Proposed Rulemaking (MegaNOPR). With this notice the FERC formally requested gas consumers and the gas industry to submit proposals and comments about ways to further structure gas pipeline transportation. MegaNOPR was followed the next year by FERC Order 636 – the Restructuring Rule. This order was a more comprehensive unbundling of the gas supply and transportation segments of the industry; it resulted in a major restructuring of the interstate pipeline industry by separating sales from transportation services. Customers could now choose supply services and transportation services from any competitor in any quantity and any combination. This essentially eliminated the need for take-or-pay contracts. The most important byproducts of Order 636 were dramatic increases in gas exploration, pipeline construction, falling prices, and greater profits for industry participants. In 2000, FERC Order 637 resolved several discrepancies in the restructuring of the industry by addressing inefficiencies in the capacity release market. Customers could now negotiate supply and transposition contracts while simultaneously negotiating better terms in other markets as a price hedge. The natural gas commodity market is now traded on the New York Mercantile Exchange (NYMEX). Deregulation of the U.S. natural gas market is considered a success and is used as a policy model for the restructuring of other public utilities. In 2004, the industry included something like 8000 independent producers, 160 pipeline operators with 285 000 miles of pipes, and 1500 local distribution utilities with 833 000 miles of pipes (ABS Energy Research 2004). Federal Water Policy Current U.S. public policy toward water utilities is less intrusive than the deregulation programs underway in the power and gas industries. There are no federal agencies pushing for restructuring, deregulation, or unbundling of services in the water utility industry today. However, the pressures for restructuring in those industries are likely to put increased pressure on managers and workers in water utilities to become more efficient (Rubin
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1998; Beecher 2003). This does not mean to say that water utilities are not subject to government regulation. Indeed, the opposite is true; water utilities are subject to regulatory actions on three separate planes: water quality, quantity, and price. The point is that government regulation is simply different for water utilities than it is for electricity and natural gas. One of the major reasons for this is the different ownership picture. Whereas something like 75 percent of the electricity industry and 80 percent of the gas industry is investor owned, less than 10 percent of the nation’s 53 400 water utilities are investor owned; most water systems are municipal operations. Restructuring of the energy industry was seen as a way to reduce the cost of electricity generation by substituting low-cost generation process for older, higher cost, large capacity plants, many of which were approaching the end of their useful life and needed either replacement, augmentation, or extensive revamping. In addition, smaller plants could be brought on line much faster than hydroelectric, nuclear, or coal-fired generating plants. The water utility industry faced different problems. Construction of new water production plants is more costly than those they are designed to replace. A major reason for this is the greater treatment requirements required by major shifts in public policy that resulted from passage of the Safe Drinking Water Act of 1974. For these and other underlying technological reasons, the water industry does not enjoy the same benefits from restructuring enjoyed by electricity and natural gas. Increasing competition in the water industry would not result in a cost savings to consumers. The electricity industry can gain cost savings because new, smaller energy sources can be constructed at less than the average cost of existing sources. Savings in the gas industry are possible because production costs may vary greatly among the many independent producers. The ability of a gas user to gain transmission access for the gas purchased from a low-cost producer enables that gas user to substantially lower the overall acquisition cost of the gas. On the other hand, federal health and terrorist protection legislation have made new water collecting, storing, and purification facilities extremely expensive to construct. Adding to the cost is the need for ever larger plants; purification and storage facilities must be centralized as much as possible to control water supply costs. Urbanization is making this more and more difficult and costly to achieve because of high costs to purchase land for the new plants near to service areas. Scott Rubin summarized the impact of these differences in the following terms: In summary, both the technology of water production and the characteristics of water itself make it very unlikely that the water industry will be restructured in the same way as the energy industries. Multiple water suppliers serving a single market and competing for customers is very unlikely. (Rubin 1998, p. 10)
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Instead, restructuring of the water industry is more likely to consist of the separation of water-production plant ownership from the transmission and distribution of water. This has already occurred in several locations, as companies that are independent of the distribution operators have constructed new water treatment plants. Treatment services are then sold to the distributor, who is not saddled with the need to construct new facilities to meet growing demand. In other locations municipalities have contracted with private firms to operate the water systems, with ownership remaining in the hands of the city.
MOVES TO RESTRUCTURE THE UTILITY INDUSTRY Utility policy in the United States began a new chapter during the administration of President Jimmy Carter when three important pieces of utility legislation were enacted (1) the Power Plant and Industrial Fuel Use Act (PPIFU), (2) the Natural Gas Policy Act (NGPA), and (3) the Public Utility Regulatory Policies Act (PURPA). The Fuel Use Act prohibited the use of oil or natural gas to power any new electric energy plants; the intent was to reserve natural gas for heating and other high value uses. The NGPA deregulated the price of newly discovered natural gas. Passage of PURPA in 1978 opened the wholesale electric power market to non-utility generating companies. PURPA was designed to help reduce U.S. dependence on foreign oil, support new sources of supply for electricity generation, and thus lower electricity prices. Increasing the diversity of supply for electricity generation was also seen as a way of reducing the nation’s dependence upon foreign oil (Smeloff and Asmus 1997). PURPA also called for restructuring of the traditional regulated fully integrated power and gas systems. Proponents of restructuring cited the successful restructuring of other network industries, including natural gas, airlines, and telecommunications, as justification for bringing competition to the electric utility industry. Utilities were required to purchase power generated by nonutilities using nontraditional generating methods. This provided financial incentive for investments in such nontraditional methods as wind-powered generators, geothermal and biomass steam powered turbines, fuel cells, and gas turbines. Benefits claimed for introducing competition in the production of electricity included improved generation efficiency, diversified supply, promotion of innovation, and even lower prices. Success in opening the wholesale market, proponents argued, would eventually be extended to the retail market, where all consumers would have the opportunity to choose their supplier and pick an electricity service that best fitted their individual needs.
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In 1998, non-utilities were responsible for 11 percent of the total generation in the nation and were contributing 406 billion kilowatt-hours (kWh) to the electric system. PURPA was followed by the passage of the Energy Policy Act of 1992 (EPAct). One aspect of EPAct was to further press wholesale deregulation by opening up transmission access to non-utilities. In return, regulated utilities were permitted to build new merchant plants outside their service territories. Other landmarks in restructuring the utility industry were regulatory Orders 888 and 889 issued by the Federal Energy Regulatory Commission. Both orders were issued in 1996 and were designed to pave the way for increased participation by nonutilities and promote wholesale competition by eliminating local utility monopoly control over transmission. The combined effect of these orders required public utilities that controlled transmission to develop open access, nondiscriminatory transmission tariffs and to provide existing and potential users with equal access to transmission information. These orders also began the process of ‘unbundling’ existing utility functions by separating transmission of electricity as a stand-alone service from generation and distribution. The opening of access to transmission lines was a significant step in restructuring the utility industry. By 1999, FERC pushed the issue of opening the transmission grid one step further with the adoption of Order 2000. This order encouraged states to form regional transmission organizations (RTOs) to improve multi-state operations of the transmission grid. The RTO was to serve as a multi-state, independent organization to manage the operation of the transmission grid for particular regions. The order provides specific (but voluntary) guidance concerning a minimum set of eight functions that an RTO must be able to perform, but the order leaves it up to the states and the utilities to develop both the geographic footprint (how large an area the RTO is to serve) and the governance structure of the RTO. In 2001, FERC clarified its goals by arguing for the formation of as few as four very large RTOs to cover the entire national grid. The suggested eight minimum functions are: 1. 2. 3. 4. 5. 6. 7. 8.
Responsibility for tariff administration and design Congestion management Parallel path flow Ancillary services Total transmission capability and available transmission capability Market monitoring Planning and expansion Inter-regional coordination.
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In theory, splitting the traditionally integrated functions of a utility – power generation, transmission, and distribution – into separate functions would expose cross-subsidies and inefficiencies, and competition among power generators would lead to lower prices for all classes of customers. Restructuring was designed to introduce open market competition only in electricity generation. Transmission and distribution services would still be subject to varying levels of regulation. By 2000, almost half of the states were pursuing some form of restructuring. However, several recent events have cooled the enthusiasm for abandoning the traditional heavily regulated and integrated utility system. Foremost among these was the California electricity crisis. The state garnered daily headlines as a series of events, including a flawed restructuring plan, left California facing huge price increases, potential blackouts, and bankrupt utilities. Mixed Results for Restructuring Regardless of their product or service, public utility services are composed of three similar components: production, transmission, and distribution. For electricity, production means power generation. Power is generated by falling water in hydroelectric systems, by steam-powered turbines using fossil fuel, geothermal, or nuclear power energy, by wind-power generators, and by gas turbines using natural gas or propane fuels, solar collectors, and fuel cells, among others. Natural gas is collected at wells, often as a byproduct of petroleum production. By far the majority of fresh water consumed in the United States is either released from reservoirs behind dams, withdrawn from rivers or streams, or pumped from wells that tap into underground aquifers. Although an increasingly important source of potable water in any areas, desalination was still not common in the US as of 2004. Small amounts of well water with high salt content is either restricted to agricultural use or treated chemically and mixed with low-salt content water before distribution to residential or commercial customers. Transmission is similar for all three utilities. Electric power is moved over high voltage transmission lines; gas is transported by large volume pipeline; water is pumped through pipeline or moved by aqueduct. Distribution is also similar. Electric power is distributed over low voltage overhead or underground power lines; gas and water is distributed via underground pipe networks. Traditionally, utility networks have tended to be vertically integrated firms that provided all three services: generation, transmission, and distribution. Some observers and policymakers felt that this system resulted in higher rates to residential customers in order to subsidize costs of production
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and/or transmission of product to large industrial customers. Residential customers were thought to be subjected to price discrimination as commercial and industrial prices for utility products were lower than they were for residential customers. Furthermore, integrated utilities were able to deny competitors access to their private transmission and distribution facilities. This was seen as resulting in scale inefficiencies, which further raised the price of utility products. The utility industry restructuring actions that occurred during the 1980s and 1990s were implemented in order to redress perceived price discrimination and to reduce what were believed to be unnecessarily high prices for utility services. This policy shift that brought about restructuring was driven by a global trend that combined elements of minimalism in government, accountability, and market efficiencies in the management of public services. This multi-faceted movement is reflected in the global drive toward deregulation and market competition known as the New Public Management that continues to this day. Today, the policy of restructuring utilities appears to be somewhat in limbo. A number of states put their restructuring plans on hold after the problems encountered by California in the year 2002. The Congress of the United States failed to pass the Energy Policy Bill of 2003. Among a host of other features, the 2003 bill would have designated ‘national interest electric transmission corridors,’ and authorized the Department of Energy (DOE) to issue permits for transmission line construction in the corridors. The legal right of government to acquire – with fair compensation – private land for public use (the right of eminent domain) was included in the bill in order to facilitate the construction of any needed new transmission lines. Parties other than utilities or transmission operators were to be allowed to finance construction of the new DOE-owned transmission lines. Repayment was to occur through rates charged to customers. In addition, in order to ensure that terms and conditions of transmission rates are not discriminatory, the FERC would have been given jurisdiction over unregulated transmitting utilities. Unregulated transmitting utilities are publicly owned, and include such organizations as Bonneville Power. If passed, the 2003 bill would have required unregulated transmission utilities to provide the same transmission rates, terms, and conditions as regulated utilities, thus eliminating any competition between the two.
ADDRESSING THE WORK THAT REMAINS Before restructuring can continue, policymakers need to answer a number of questions, including the following (Mattoon 2002):
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●
●
●
●
Is the physical infrastructure for production and transmission adequate to support new market entrants and a competitive market? Do incentives exist for investing in new utility facilities? If so, are they adequate? If not, how can the incentives be improved? Must new institutions be developed to enable the new structure to deliver their services? Should these be federal, regional, state, or quasi-public institutions? What is the role for existing regulatory institutions? Should restructuring expose consumers to changes in utility prices, even when those prices can be volatile? What is the relationship between meeting environmental goals and generating greater supplies of electricity, natural gas, and clean water? Can the two successfully coexist?
Moreover, policymakers need to consider the role of the utility consumer in any restructuring plan. For restructuring to succeed, consumers need to be informed of legitimate market-based changes in prices, and to be able to react to the price differentials. Price signals that communicate results of proposed fundamental changes in the cost of production, transmission, and distribution need to be passed through to consumers, who should then be given the opportunity to indicate their views. Utility Governance and Public Policy The system of governance of utilities in the United States is fragmented. For the most part, large, vertically integrated, investor-owned utilities are responsible for generating, transmitting, and distributing electric power to customers. Restructuring is rapidly changing this picture, however. The very large vertically integrated power company is becoming a thing of the past. An increasing amount of the nation’s electricity is generated by independent nonutility organizations. Some of these generators are quite small. The greatest change in the industry has occurred in the transmission sector. Most power is transmitted by regional transmission organizations, which are independent organizations that are required by the FERC to transmit power produced by all generators. At the end of the line are the distribution and marketing firms that remained after restructuring broke up the formerly vertically integrated investor-owned power companies. However, other forms of electric utility ownership also function in this environment, including municipal ownership, cooperative ownership, and even federal power utilities such as the Tennessee Valley Authority and the Bonneville Power Authority.
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In the gas utility industry, a large number of independent producers collect gas at the wellhead. At the distribution end, gas is delivered to customers in much the same way as in the electricity field: by investor-owned local distribution firms. The big difference in this industry is in the transmission system. Customers are free to purchase gas directly from any bestprice producer, while a small number of independent pipeline companies are required to provide open access for moving (transmitting) the purchased gas to the customers’ point of delivery. In almost every case, participants in the gas industry are private, investor-owned organizations, although a few municipal distribution systems still exist. The water and sanitation utility network systems have traditionally been publicly owned, relatively small systems, constructed and operated by municipalities. Because water is so essential for maintaining life, quality has long been a major concern in this industry. It has resulted in an insertion of an additional step in the production–transmission–distribution chain: water treatment. Restructuring of the U.S. water industry is proceeding much slower than it did in the energy fields. Rather than unbundling of services, the dominant trend seems to be privatization of complete systems. The privatization model is currently dominant throughout most of Europe. A typical example is the former municipal water system in Cambridge, England, that for nearly a decade has been owned by a Spanish multinational corporation. This same pattern exists across the European Union, Australia, New Zealand, and Canada, as well as in Latin America and Asia. These differences in governance have important ramifications for regulatory outcomes. While large investor-owned utilities are subject to review by state public utility commissions, many public power authorities are exempt from these requirements. This fragmented structure makes electricity a policy area with many participants and little central planning or review authority, except within the balkanized areas served and regulated by a public authority.
FUTURE UTILITY POLICY ISSUES The national and some cases, international, associations of electric, gas, water, and sanitation utilities are forums for addressing the big issue policy questions faced by all utilities collectively, and each industry independently. Associations meet early each year to identify the more pressing issues they feel will have the greatest impact upon their operations. An example was the January 20–21, 2003 summit meeting of the National Association of Regulatory Utility Commissioners (NARUC). Commissioners met to discuss the major regulatory policy issues they faced and to consider the
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options available to them for dealing with the issues that would most affect the states in 2003 and beyond. Five key concerns were identified in a report on the conference produced by the National Regulatory Research Institute (NRRI 2003b); other public utility associations produce similar policy issue platforms. For example: 1.
2. 3. 4.
5.
The Federal Energy Regulatory Commission’s initiative for establishment of a ‘standard market design’ (SMD), and particularly the jurisdictional implications of the concept; State perspectives on government telecommunications policy; The impact that competition in the utility supply chain will have on consumer protection and service quality regulation; The implications for oversight of transactions between affiliate organizations resulting from reform of the Public Utility Holding Company Act of 1935; The impact that implementation and changes in energy and environmental polices will have upon state regulatory commissions.
SUMMARY The activities of public utility managers are influenced by public policy, corporate policy, and company or organization policy. Public policy is a reflection of particular attitudes, intentions and actions of policymakers that affect society; examples include industrial, education, welfare, public safety, environmental, energy, water policies, and the like. Public policy shapes the types of laws passed by federal, state, and local governments and provides a framework for the rules and regulations developed by government agencies for implementing the laws. Public policy is itself shaped by public opinion. Public policy also influences the amount and shape of regulatory content and procedures, locating decisions, utility taxation, and other public service functions and operations. Corporate policy refers to the operational guidelines that shape and frame the corporate mission and fundamental operations of an organization. Corporate policy is shaped by the actions of an organization’s directors and by the CEO. Corporate policy is manifested in the vision of the leadership and the mission statement of the organization. Company policy refers to the specific rules, regulations, procedures, and practices that guide managers and workers in their interpersonal and interorganizational actions. Because policy exists at more than one level in all organizations, managers often face difficulties when making decisions when the guiding policies conflict.
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The results of public policy on utilities is seen in the character of the laws enacted, regulatory actions taken, court decisions handed down, and the behaviors and attitudes expressed by legislatures and the public on utility operations and issues. Moreover, public policies seldom if ever remain permanent; they are always subject to change. Policy changes often occur as a result of some catastrophic event. The utility industry received little public attention during the first two decades after its beginnings in the 1880s. Governments and the courts felt that utilities were natural monopolies providing essential public services. As long as the services continued unabated and remained generally affordable, government tended to follow the same hands-off policy it followed with all businesses. Government policy toward public utilities took its initial shape within the framework of a shift in government’s attitudes toward business in general that occurred in the last decades of the nineteenth century. These policy changes occurred as part of what we now call Progressive Era reforms. A few states’ efforts to regulate railroads forced the federal government to examine its traditional laissez-faire policy toward business. State legislatures passed laws aimed at redressing perceived issues of restraint of trade, unfair and discriminatory pricing, and the anti-competition activities of trusts. A second wave of changes in public policy toward utilities occurred after the stock market crash of 1929. The Securities Act of 1933, Securities and Exchange Act of 1934, and the Public Utility Holding Company Act of 1935 severely restricted the power and scope of action of utility holding companies. These laws also brought the federal government into greater regulatory control of the utility industry. Under President Franklin Roosevelt, the federal government for the first time became heavily involved in the utility industry, developing huge utility projects and networks, including the Tennessee Valley Authority and the Bonneville Power Authority. A third wave of changes in public utility policy in the United States began in the late 1970s. Three important pieces of utility legislation were signed by President Jimmy Carter: (1) the Power Plant and Industrial Fuel Use Act, (2) the Natural Gas Policy Act, and (3) the Public Utility Regulatory Policies Act. The utility industry restructuring actions of the 1980s and 1990s were implemented to redress perceived price discrimination and reduce what were believed to be unnecessarily high prices. This policy shift that brought about restructuring was driven in large part by a global trend that combined elements of minimalism in government, public accountability, performance appraisal, and market efficiencies in the management of public services.
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ADDITIONAL READING Brown, Matthew H. and Richard P. Sedano (2003), A Comprehensive View of U.S. Electric Restructuring with Policy Options for the Future, Washington, DC: National Council on Electricity Policy. Cochran, Clark E., Lawrence C. Mayer, T.R. Carr and N. Joseph Cayer (1996), American Public Policy, 5th edn, New York: St. Martin’s Press. Jacobson, Charles David (2000), Ties that Bind: Economic and Political Dilemmas of Urban Utility Networks, 1800–1990, Pittsburgh: University of Pittsburgh Press. Robinson, Colin (ed.) (2002), Utility Regulation and Competitive Policy, Cheltenham, UK and Northampton, MA, USA: Edward Elgar.
3.
The public utility ethics challenge
Researchers investigating possible unethical activities of traders at the bankrupt energy trading company Enron, found a number of incriminating statements in the more than 2600 hours of recorded conversations taped during the 2000 and 2001 energy crisis. The recordings indicated that company traders regularly over-priced customers during the power crisis in California and other Western states (Said 2004). Enron regularly recorded their traders’ discussions to have a record of the rapid-paced ‘wheeling and dealing’ for evidence in case of trade disputes. The tapes included records of traders, who boasted of creating artificial congestion on transmission lines, shipping power away from areas where it was needed, lying about power shortages and competition for power in order to drive up spot prices, and joking about profiting from high prices for power as stealing money from ‘those poor grandmothers in California.’ This evidence of greed and market manipulation is indicative of a widespread failure in the moral standards of an important segment of the public utility industry. Following the disclosure of these and similar ethical breakdowns, both public and private organizations have been increasingly subjected to regulatory oversight and control. The drive for deregulation and privatization has been put on hold in much of the country – an outcome with significant impact on the entire industry. And this crisis in the ethical standards of utility industry managers is just one of a number of forces shaping the industry for good and bad. In addition, utility managers everywhere are also being affected by external forces emanating from the global economic, political, environmental, and social environments. Government agency administrators and managers in investor-owned utilities are regularly faced with demands for ethical reform emanating from the popular press, the general public, and a growing number of crusading social scientists. Legislators are urged to enact more and more stringent ethics laws and codes. All types of organizations are required or strongly urged to design and adopt comprehensive programs of development education and training in ethical behavior for managers and staff. Calls for ethics reform have been directed at every level of government, from the Office of the President of the United States to the smallest local special service district. Ethical problems in public and private utilities run the gamut from sexual harassment to misappropriation or outright embezzlement of millions and 39
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billions of dollars. Ethics breakdowns are loudly pointed out by the press as examples of the poor quality of public servants in general. Examples include newspaper stories of the alleged sale of presidential pardons and diplomatic passports (New York Times, June 17, 2001; A1), charges that a town mayor and nine others in Illinois misappropriated $10 million in taxpayers’ money; and the conviction of a former New Jersey mayor on charges of laundering drug money and accepting bribes from racketeers (San Francisco Chronicle, June 16, 2001; A2 and A5, respectively). Public utilities and other businesses that serve the utility industry are not immune to allegations of ethical misconduct, as the example of Enron attests. A number of energy companies associated with Enron were being investigated for fraudulent dealings in the California energy crisis. Sherron Watkins, a former vice-president at Enron, has been credited with warning senior managers at the bankrupt energy trading company about what she has called ‘an elaborate accounting hoax,’ and ‘what I thought was the worst accounting fraud I’d ever seen.’ After the company collapsed in 2001, U.S. Congressional investigators found her warnings buried in boxes of documents and brought her to Washington to testify before the United States Senate. Enron’s chief financial officer was accused of becoming general partner in an investment partnership, LJM, while employed at Enron. He raised $600 million in limited-partnership funds and then proceeded to conduct business activities that maximized returns for the limited partners, not Enron’s stockholders. The conflict of interest was that LJM’s sole reason for existing was to do business exclusively with Enron. Nearly all of the transactions had no economic substance, but paper profits were recorded. Addressing the Academy of Management on August 3, 2003, Watkins described Enron’s accounting practices this way: Enron’s accounting moved from creative, to aggressive, to fraudulent, like the pot of water moving from cool to lukewarm to boiling; those involved with the creative transactions soon found themselves working on the aggressive transactions and were finally in the uncomfortable situation of working on fraudulent deals. . . . It is now clear that there were problems in the executive suite at Enron and in the other companies accused of fraudulent behavior, but what happened to all the watchdog groups in business to protect investors? That whole system failed at Enron. Enron’s outside auditors failed. The legal counsel Enron received is suspect. The investment bankers and traditional bankers seem to have been ‘in on it.’ Arthur Anderson is out of business because of Enron. (Watkins 2003, p. 119)
THE GROWING ETHICS CHALLENGE Citing a recent Gallup Poll, USA Today newspaper reporter Karen Peterson (2001) wrote that, for only the second time in half a century, ethics
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and morality are near the top of a list of the major problems that people believe are facing the nation. Gallup reported that 78 percent of the public feels that the nation’s moral values are somewhat or very weak. Watkins quoted a July 2002 Gallup Poll that asked the public if members of 20 groups listed could be trusted. Business leaders received only a 20 percent confidence level, the lowest it has been in decades. The rating is right next to that given for car salesmen. The airing of misconduct typically begins with a whistleblower airing allegations of employer or fellow employee misconduct; newspaper headlines pick up on the story and question the sincerity of administrators who deny the claims and the denials of government watchdogs whose responsibility it is to monitor utility operations. Congress begins to hold legislative oversight hearings on misconduct by the utility and/or regulatory agencies. In the past, other than more bad press for everyone involved, little concrete change took place, and often the utility or organization in question continued operations with little change (LaFollette 1994). Some states have adopted new laws to prevent the old ‘slap-on-the-wrist’ manner of dealing with ethical infractions. In Washington State, for example, the legislature passed a law that took effect in January of 2003 that gave the State Department of Licensing disciplinary power for enforcing its regulations, including the right to issue cease-anddesist orders (Lewis 2003). In an early action, the department ordered a Texasbased, third-party company that collects utility bills on behalf of landlords and property managers to stop operating without a collection agency license. The field of public management has a long history of scholarship and programs aimed at fostering the ethical behavior of public service mangers (Rohr 1998). The problem of unethical behavior by utility and related industry managers became a particularly important political issue for Congress in 2001 with the plight of the California electric power industry and allegations of gross over-charging and staged shortages to drive up wholesale energy prices. According to Michael Burr (2003), the series of scandals that followed the California energy crisis and Enron collapse resulted in demands by regulators and investors that utilities demonstrate that they are ‘squeaky-clean, inside and out. From American Electric Power Co. to Maine Public Service, energy and utility companies across the nation are renewing their commitment to ethics and good governance.’ Box 3.1 describes how California regulators have reacted to the alleged bogus shortages and wholesale price escalation and their actions to avoid problems like those it suffered through the energy crisis of 2000 and 2001. Legislators are often slow to investigate and monitor the management practices of public utility administrators and managers when they receive allegations of misconduct from constituents. In fulfilling their oversight
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BOX 3.1
CALIFORNIA TAKES STEPS TO AVERT SUMMER POWER SHORTAGES
During 2000 and 2001, California power customers were hit with a higher than normal number of generating plant outages. These resulted in a shortage of power, which in turn forced prices higher and caused some rolling blackouts. Some of the outages were alleged to be intentional. Independent generating firms were accused of creating artificial shortages. Investigators have determined that some companies faked maintenance and mechanical problems in order to hold back power to jack up the wholesale price – and profits – of electricity. One firm was charged with shutting down four of its five California generating plants to further tighten supplies and boost prices. The firm responded to the charges by saying that their actions were legal at the time. During the energy shortage and wholesale price run-up, state regulators kept a cap on retail prices. This brought a number of power distribution companies to declare bankruptcy. Since then, California legislators have given PUC regulators new tools to make sure artificial shortages and price run-ups are not repeated. All generating plant operators must adhere to new rules regarding maintenance, operations, and recordkeeping. Generating companies must secure PUC approval before plant shutdowns. State PUC regulators may carry out audits, investigations, and surprise inspections to enforce the new rules. The executive director of the Independent Energy Producers, which represents private generators in California, was quoted as saying that his members believed that the California PUC did not have the authority to enact and enforce the new standards. Source:
Elizabeth Douglass, Los Angeles Times, May 7, 2004, p. C2.
responsibilities, Congress has the power to authorize inquiries and hold hearings on issues of (1) allegations of over-charging for public utilities, (2) the qualifications of the state utility commissions responsible for setting and monitoring utility rates, and (3) the organizational policies which guide and influence such processes. Congress conducts these oversight activities in three ways: (1) by directly communicating with responsible agency personnel, (2) by holding hearings, or (3) by initiating investigative reports by appropriate regulatory and watch-dog agencies and organizations.
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According to one widely cited author on the topic, Terry Cooper (1998), public interest in business and government ethics has mushroomed. This interest has resulted in a growing demand for in-service training, publication of many ethics articles, and professional conferences devoted solely to ethics problems in public and investor-owned public utilities, industry regulators, and other arms of government.
WHAT DOES ‘ETHICS’ MEAN? Ethics, a branch of philosophy, is the study of the moral behavior of humans as individuals and within society. It has been further defined as the set of principles that govern the conduct of an individual or a group of persons, and briefly as the study of morality or moral behavior (Velasquez 1998). Some readers may not be familiar with the terminology encountered in ethics discussions. Therefore, and at the risk of explaining the obvious, a few definitions are included here to provide a framework for the discussion that follows. Morality refers to the standards that people have about what is right, what is wrong, what is good, or what is evil; these standards are the behavior norms of a society. Moral behavior is acting in ways that follow the moral standards that exist in society. Collectively, the behaviors of individuals and groups in a society, as well as their dispositions to behave in particular ways, are referred to as the ethos of the group. Moral standards are the rules by which a society functions. Examples of moral standards include the commandments: Do not kill, Do not steal, Do not lie, etc. Standards are about what behavior is acceptable, what is ‘right’ and what is ‘good’ in society, and their opposites, of course. While moral standards often differ from time to time, they remain relatively constant for at least a generation or more. When they do change, they tend to do so very slowly. Now that we have a definition of ethics, we next need to determine what it is we meant by ‘behavior that is unethical.’ In the specific sense of public utility management, we are referring to the broad concept of public service misconduct. Misconduct, in the words of Fox and Braxton (1994, p. 374), ‘encompasses acts of deception – alteration of data or materials, false representation of authorship or originality, and misrepresentation to advance oneself or to hurt the career or position of another.’ Opinions about what constitutes unethical behavior and what moral standards to follow vary from society to society, and often from organization to organization within the same society. There are few absolutes in ethics, and the dichotomies are exacerbated when conflicting ethos exist to provide
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similar services, as they do in public versus investor-owned public utilities. Still, the fundamental standards of behavior tend to be quite similar throughout the industrialized nations of the world. This is so because, if standards were wildly different, nations would have a difficult time cooperating in such value-laden areas as international relations, commerce, and other global activities. What distinguishes moral standards from standards that are not moral? Velasquez (1998) has identified five characteristics of moral behavior that make this distinction (Figure 3.1). First, moral standards are concerned with matters that people think can seriously injure or benefit human beings. Second, most people absorb their initial moral standards as children. People will often typically revise these moral positions as they mature; some of that revision occurs in response to the organizational culture they find as they move through their careers. Although it is not impossible, it is difficult for person’s moral standards to be completely reshaped by the decisions of authoritative bodies; ethical behavior can seldom be successfully legislated, as America’s failed experience with Prohibition and the sale and consumption of illegal drugs today will attest. Third, by their very nature as fundamental norms of behavior in
Behavior evoked by action situation characteristics
Emotions evoked by moral and/or immoral behavior
Moral behavior of workers and managers in situations involving social goods and services
Perceived equality of impact resulting from immoral actions
Character formed by early childhood experiences
Cultural preferences for moral behavior in the society
Figure 3.1 Major factors influencing moral behavior of workers and managers in public utilities
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a society, moral standards are preferred over other values, including selfinterest. Fourth, moral standards are based on impartial considerations; they apply equally to all persons in society. Finally, moral standards evoke special emotions, including guilt and shame, and are associated with a special vocabulary; words such as good and bad, honesty, greed, justice, and injustice are examples. Western moral standards have evolved from a number of different philosophical traditions, some of which may be as old as recorded time.
SOURCES OF MANAGERS’ MORAL STANDARDS Today, a number of different ways to approach an ethical situation have evolved from these earliest guidelines for the moral behavior of workers in public service. The model in Figure 3.1 illustrates how different antecedents might shape and direct a manager’s moral behavior. At the heart of the model are the moral behaviors of workers and managers in all public situations. An individual’s behavior is sparked by the characteristics of the situation. For example, if a manager believes his or her position depends entirely on a particular decision, this belief will influence the decision. Research has suggested that the moral character of most individuals is largely in place by the time the person reaches seven years of age. From that time on, behaviors that merge with these standards reinforce the person’s beliefs and attitudes. Behaviors that conflict with the standards evoke tension and other emotions. Some factors may act to ameliorate these negative tensions in the individual, however. Among them are first, the perceived equality of treatment individuals within the organization receive for questionable behavior. Are other employees and management treated the same? Are rewards and punishments meted out equally? Second is the organizational culture. Does the work climate encourage or discourage moral behavior?
DIFFERENT ETHICAL STANDARDS SHAPE MORALS A number of different ways to describe moral behavior have been developed over centuries of philosophical thinking on this issue. The most popular approaches include the teleological approach known as utilitarian ethics and the deontological theory of ethics based on universal rules (called rules ethics). Others include rights theories, the ethics of justice, caring ethics, and virtue ethics (Velasquez 1998; Garofalo and Geuras
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1999). Business ethicists generally agree with this conclusion of Donaldson and Dunfee (1999, p. 12): No single theory has emerged that is fully capable of providing guidance about the gamut of challenging business ethics matters that fill business ethics casebooks and confront practicing businesspeople.
As a result, academics tend to resort to using traditional ethics theories when describing problems of professional ethics. Several of these major traditional theories are discussed in the following pages, beginning with utilitarianism. Utilitarian Ethics Utilitarian ethics is based on the view that the ‘right’ action or policy is the one that will result in the greatest benefit (or the lowest costs) to society. Thus, decisions on actions and polices must be evaluated according to their net benefits and costs. It is concerned with the consequences of an action, not the means to achieve the results. Today’s cost–benefit analysis is based on this principle. Because it supports the value of efficiency, utilitarianism is often used in the resolution of political dilemmas. A key characteristic of utilitarianism is that the benefits need not be equally distributed; some people may not benefit at all, while others may even be negatively impacted – they will lose more than they gain. What counts in the final analysis is the greatest good for all concerned. The great moral dilemma with utilitarianism is determining who is to decide what is meant by ‘good’ (Malhotra 1999). Kant’s Categorical Imperatives (Rule Ethics) The basis for rule ethics comes from the writings of philosopher Immanuel Kant (1724–1804). Kant believed that all human beings possess some rights and duties, and that these exist regardless of any utilitarian benefit they might have for or against others in a society. Kant proposed moral principles he called ‘categorical imperatives’ to make this point. Kant’s first categorical imperative states that an action is morally right if – and only if – the reason for doing it is one that the person would be willing for everyone to act upon in a similar situation. There are two parts to Kant’s categorical imperative concept; (1) the concept of universalizability – that is, the principle must apply to everyone, and (2) reversibility – people must be willing to have all others use the same concept in the same way that the first actor treats other persons. Kant’s
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second imperative holds that an action is morally right if – and only if – when performing the action, a person does not use others as a means for improving his or her own interests. Thus, when making an ethical decision, administrators must respect the right of others to choose freely for themselves. This concept was clearly breached when Enron energy traders chose to reap huge profits at the expense of energy industry participants and consumers. Earning a profit in the Western economic system is clearly morally permissible; using others who are unable to defend themselves as a means for reaping excessive personal profits is not. Rights Ethics A ‘right’ is often defined as a person’s entitlement to something. Because of its focus on the individual, it differs from the utilitarian approach, where the focus is on the greater good of a society. Rights have been classified in several different ways. In one classification system, two types of rights are included in ethics, legal rights and human rights. Legal rights are based upon laws; consumer protection and contract rights are examples. Human rights, on the other hand, are culturally based; they provide people with a way of justifying their actions; they are also associated with duties. A second way to classify rights is by determining whether they are first generation or second generation rights (Joseph et al. 2000, pp. 3–4). First generation rights include civil rights and political rights. Civil rights are rights that apply to citizen’s physical integrity, the procedural right of due process, and non-discrimination rights. Political rights enable citizens to participate in the political life of their society. They include such rights as freedom of expression, assembly and association, and the right to vote. Civil and political rights are called first generation rights because they are a large part of the content of the Bills of Rights that were written in the eighteenth and nineteenth centuries. Collectively, they are considered as rights to be free from government influence. Second generation rights embrace economic, social, and cultural rights. Among these are rights to an adequate standard of living, right to an education, and the right to good health. Collectively, second generation rights are considered to be rights that require positive government action. Of the two sets of rights, second generation rights tend to be less developed than first generation civil and political rights. Several key concepts in political science are founded upon Kantian rulebased rights theories. Among others, these include the idea that all people have positive rights to work, clothing, housing, and medical care; that everyone has a negative right to freedom from injury or fraud; and, that humans have the right to enter into contracts.
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Justice Ethics Moral standards based on the idea of justice include the concept of fairness. Together, these ideas contribute to three fundamental bases for moral behavior: Distributive justice, retributive justice, and compensatory justice. Distributive justice is concerned with the ‘fair’ distribution of society’s benefits – and burdens. The idea of a just distribution based on a person’s contribution to society is the value behind the capitalist system, whereas distributive justice based on needs and abilities underlies socialism, and justice, as freedom to do as he or she chooses, is the idea behind libertarianism. Retributive justice is concerned with the providing of punishments and penalties that are ‘just.’ Thus, a person should not be considered to be morally responsible under conditions of ignorance or inability. This principle is the idea behind the requirement for enlightened consent for participation in research studies. Compensatory justice supports the idea of compensating people for what they lose when they are wronged by other individuals or by society (including government). Requiring the energy trading companies convicted of illegally manipulating the wholesale energy market in 2000 and 2001 to compensate the victims is an example of compensatory justice. Caring Ethics The ethics of caring means making a decision in the face of an ethical dilemma based upon a genuine caring for the best interests of another individual. Key virtues of the caring administrator include friendship, kindness, concern, and love for fellow human beings. As might be expected, these ethical standards are often employed in describing decisions made in social welfare agencies and activities. The care ethic emphasizes two moral demands. First, because we all live in our own web of relationships, we should preserve and nurture the valuable relationships we have with others. Second, we must care for those with whom we are related by attending to their particular needs, values, desires and concrete well-being as seen from their perspective. This also means responding to the needs, values, desires, and well-being of those who are vulnerable and dependent on our care. Three different types of care ethics come into play in social situations: caring about something, caring after someone, and caring for someone. In the political world, the applicable ethic is caring for someone. It focuses on people and their well-being, not on things (Velasquez 1998).
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Virtue Ethics Based upon the writings of Aristotle and others, virtue ethics refers to the idea of using society’s virtues as the basis for making ethical decisions. Aristotle identified four ‘pivotal’ virtues: courage, temperance, justice, and prudence. St. Thomas Aquinas added the following ‘Christian’ virtues: faith, hope, and charity. In today’s society, the virtues considered most important include honesty, courage, temperance, integrity, compassion, and self-control – terms often used to describe the ‘ideal’ public servant. Vices are the opposite of virtues; they include such examples of ‘bad’ behavior as dishonesty, ruthlessness, greed, lack of integrity, and cowardice. These are considered to be undesirable because of the way they can destroy human relationships. Velasquez described the thinking that shapes decision-making in virtue theory in the following way: An action is morally right if in carrying out the action the agent exercises, exhibits, or develops a morally virtuous character, and is morally wrong to the extent that by carrying out the action the agent exercises, exhibits, or develops a morally vicious character. (Velasquez 1998, p. 137)
Which, if any, of these ethical principles should guide administrative behavior for workers in the public utilities? For many, the question is moot; no choice is necessary, let alone possible. Public service ethics is ‘eclectic, eccentric, and undisciplined,’ and is, therefore, ‘interwoven into a single moral complex’ (Garofalo and Geuras, 1999, pp. 45 and 97). Out of these diverse underlying principles that characterize public service ethics have emerged many of the laws (rules) that define specifically what utility managers and administrators can and cannot do. Laws forbidding discrimination and sexual harassment, regulatory rules and procedures for setting rates, and even what customers can and cannot be served, are examples. However, it is not enough to simply do what is legal; public utility administrators have a moral responsibility that goes far beyond adhering to the letter of the law. An example is the moral question of whether to cut off electricity service to the poor or aged in the dead of winter for failure to pay a utility bill on time, or to halt water service to a family with small children for the same reason. Ethical Dilemmas Facing Utility Managers The principal ethical question facing public utility managers often comes down to one of how to balance the need for greater good of the utility
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system and the promises given to shareholders for investing their savings, against the rights to the fundamental services required for life to all citizens in a civil society. Because there is no one comprehensive moral theory that is capable of stating exactly when a utilitarian consideration should take precedence over a right, a standard of justice, or the need for caring, the public utility administrator or manager is forced to follow his or her conscience when faced with these types of ethical dilemmas. The dilemmas that cause most difficulty for public utilities are not those associated which what Orlans (1967) described as outright ‘knavery – lying, bad faith, conscious misrepresentation to get money, or the deliberate breach of the terms on which it was obtained.’ These are practical problems of a legal nature rather than problems of ethics. Instead, the problems may be those associated with conflicts between the long-term good of the organization versus the principles of the public good. Who in any society is to decide what the best good is for the most people, and what level of pain should be allowed to make the good happen. This is the ethical dilemma of public utility management. Looking further at the ethos of public service may help the reader to a point of self-accepted closure over the issues involved.
AN ETHOS OF PUBLIC SERVICE? Most professionals like to think that their profession is in some way unique, that it has an ethics or a morality of its own, and that their ethics takes precedence over the ethics of ordinary people (Goss 1996). It is logical to assume that utility administrators, managers, and staff workers feel the same about their profession. Thus, like all professions, the public utility/public service industry is hurt by misconduct or allegations of avarice and other impropriety by persons in whom the public has placed its trust. In the long run, every one who works in the public service industry is subject to social, economic, and political control (Fox and Braxton 1994). This contention was supported by research reported by Goss in 1996. Goss compared the attitudes of 100 elected state officials with those of 378 public administrators and a random sample of 250 voting citizens. Attitudes were measured across 12 dimensions arranged in two scales of six items each. One set of items referred to the service or democratic ethos; the second set of items covered the professional or bureaucratic ethos. Public administrators valued ‘Professional competence’ above all other 11 value characteristics, and rated ‘Being an advocate of the public interest’ as the least important characteristic. Clearly, practicing administrators were more concerned with their professional skills than they were in service to the public.
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If we accept this one-state case study as representative of what we might expect to see elsewhere, public trust in elected and appointed public service managers and administrators is clearly problematic. In the Goss study, many managers and administrators of public service organizations reported different priorities than the publics they served and the legislators who controlled their activities. While both the elected legislative overseers and the public in general were most concerned with manger’s trustworthiness, mangers themselves were most concerned with maintaining their professional competence. Appointed administrators apply their skills to the job at hand in ways that are different than the public and elected legislators would have them do. From his findings, Goss found that appointed administrators are less sensitive to the public interest and individual rights than the general public, directly or through their elected representatives, would prefer them to be. The term ‘ethos’ refers to the characteristics, thoughts, and behaviors that distinguish a particular person or group. Ethics in public service exists on two dominant levels: the professional or bureaucratic ethos and the service or democratic ethos (Garofalo and Geuras 1999; Woller and Patterson 1997; Goss 1996; Denhardt 1989). This two-part ethos is illustrated in Figure 3.2. In this model, workers in public service organizations must first deal with a professional or bureaucratic ethos. This influences the ways that people perform their jobs. Administrators in both private and investorowned utilities are faced with this professional service ethos. According to Garofalo and Geuras (1999, p. 48), the bureaucratic ethos is based ‘on SOCIETAL EXPECTATIONS AND TRADITIONS OF MORAL BEHAVIOR
The service ethos (democratic)
The professional ethos (bureaucratic)
Finance ethics
Human resources ethics
Leadership ethics
Budgetary ethics
Service ethics
Value ethics
ETHICAL BEHAVIOR BY PUBLIC UTILITY MANAGERS AND WORKERS
Figure 3.2 Factors contributing to ethics of public utility management
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hierarchical control and obedience to political superiors.’ In some ways, the ethics of publicly owned utilities are not much different than the ethics of any private enterprise profession; the major distinguishing characteristic is the lack of a profit factor that motivates behavior in the private sector. The second standard shaping manager’s moral behavior is the underlying belief and commitment to public service. This is the democratic ethos (possibly an unfortunate selection of names since it can exist in nondemocratic societies as well; a better choice might have been a service ethos). These ideas deal with such values as liberty, justice, human rights, and equality (Garofalo and Geuras 1999). It is important to remember that moral standards differ from agency to agency and firm to firm, and what works in one organization may not be the right approach for others (Donaldson and Dunfee 1999). Public service workers in government organizations face ethical questions in both of these areas of morality. For example, while maintaining a sense of fiscal responsibility and professional competence in their principal areas of administrative activity, administrators are also expected to live up to several distinctively service ethos characteristics in order to retain the public’s trust. These additional characteristics include: (1) avoiding conflicts of interest; (2) maintaining impartiality toward the public and stakeholders with conflicting interests; (3) avoiding any appearance of impropriety; and (4) regularly submitting to public disclosure in most every detail of their existence (Petrick and Quinn 1997).
SUMMARY The potential for unethical behavior is a universal problem; it equally affects private sector businesses and public agencies at the federal, state, and local levels and non-government, not-for-profit organizations. Politicians, elected officials, public administrators, private citizens, society watchdog agencies, and the popular press have all called for moral reform, passage of ethics laws and codes, and greater education and training in ethical behavior for everyone involved in public service. Ethics, a branch of philosophy, is the study of the moral behavior of humans in society. Morality refers to the standards that people have about what is right, what is wrong, what is good, or what is evil. Moral behavior is acting in ways that follow the moral standards that exist in society. Moral standards are the rules by which a society functions. Moral standards have evolved from a number of different philosophical traditions. Today, at least five different ways to approach an ethical situation have evolved from
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these earliest guidelines for moral behavior. These include: utilitarian, rights, justice, caring, and virtue ethics. Humans draw upon these traditions when faced with ethical dilemmas. No one approach is more correct than any other. For example, because no one comprehensive moral theory is capable of stating exactly when a utilitarian consideration should take precedent over, say a right, a standard of justice, or the need for caring, the manager is forced to follow his or her conscience when deciding which action to take. The term ‘ethos’ refers to the characteristics, thoughts, and behaviors that distinguish a particular person or group. Ethics in public service exists on two dominant levels or ethos: the professional or bureaucratic ethos and the service or democratic ethos In the long run, everyone who works in the public service industry is subject to social, economic, and political control. In a study that compared the attitudes of 100 elected state officials with those of 378 public administrators and a random sample of 250 voting citizens, attitudes were measured across 12 dimensions arranged in two scales of six items each. One set referred to the service or democratic ethos; the second set covered the professional or bureaucratic ethos. Public administrators valued ‘Professional competence’ above all other 11 value characteristics, and rated ‘Being an advocate of the public interest’ as the least important characteristic. Elected legislators and the general public rated ‘Trustworthiness’ as the most important behavioral characteristic for public service workers. Appointed administrators apply their skills to the job at hand in ways that are different than the public and elected legislators would have them do. Goss found that appointed administrators are less sensitive to the public interest and individual rights than the general public, directly or through their elected representatives, would prefer them to be.
ADDITIONAL READING Cooper, Terry L. (1998), The Responsible Administrator: An Approach to Ethics for the Administrative Role, 4th edn, San Francisco: Jossey-Bass. Donaldson, Thomas and Thomas W. Dunfee (1999), Ties That Bind: A Social Contracts Approach to Business Ethics, Boston, MA: Harvard Business School Press. Garofalo, Charles and Dean Geuras (1999), Ethics in the Public Service: The Moral Mind at Work, Washington, DC: Georgetown University Press. Joseph, Sarah, Jenny Schultz and Melissa Castan (2000), The International Covenant on Civil and Political Rights, Oxford: Oxford University Press. Rohr, John A. (1998), Public Service, Ethics and Constitutional Practice, Lawrence, KS: University Press of Kansas.
4.
The public utility regulatory challenge
Public utilities are subject to a wide variety of local, state, and federal government regulations. These regulations began with the early attempts during the 1870s to control railroad and grain elevator trusts. The scope of utility regulations was broadened extensively with passage of antitrust legislation during the first two decades of the twentieth century. The severe shocks to the world economic systems that followed the global depression that began in 1929 and continued through the 1930s resulted in passage of many more regulatory laws, including regulations on company ownership and governance, rules on methods and timing of raising capital, limits to transactions between separate company units, and controlling how utilities are permitted to produce and distribute their products and services. More recent regulations have included limiting any action which might adversely affect the environment, standards for promoting public and worker safety, and initiating provisions for anti-terrorist activity against utility facilities. As ‘natural monopolies,’ utilities are considered to be holders of a special public trust and therefore legitimately subject to government oversight. This chapter discusses some of the more important of the federal regulations under which utilities operate. The rationale for regulation of business activities lies in our reliance upon market competition to set and control prices (Brennan et al. 2002). Businesses often use price competition to best their competitors. Consumers pay what it costs to produce and distribute goods, with suppliers’ profits limited by these competitive actions of businesses. Moreover, market competition helps provide consumers with a greater and greater number of options from which to choose how they spend their money. The key to making the system work is that enough competition exists to drive down prices to a level close to the cost of production. If this is not the case, producers are free to raise prices without worrying that customers will find other sellers, or that new sellers will enter the market to take advantage of the high profits available. If only one seller exists, the firm will enjoy monopoly power over the marketplace. When such monopoly situations develop, governments step in and use regulations as a substitute for market forces to limit the market power exercised by the firm. 54
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Portions of the public utility industry function under monopolistic conditions; a single provider is the most efficient way to serve consumers. Economists call this state of affairs a natural monopoly. A natural monopoly occurs when a single firm can supply a product or service to all buyers at a lower cost than would occur if two or more sellers tried to serve the market. In a natural monopoly, the average cost of production falls as the firm benefits from economies of scale (Chandler 1994). Decisions by the U.S. Supreme Court have recognized the beneficial outcomes of single provider operations in natural monopoly situations. However, they have also recognized that, without government oversight, a firm in a monopoly position may be tempted to raise prices above what it would probably charge if it were not operating in a monopoly condition. To make sure that overpricing does not occur, the courts have sanctioned the imposition of federal, state, and local controls over utility operations. While these controls are designed to guarantee that price gouging does not occur, they also ensure a steady source of the utility product and a reasonable, or ‘fair,’rate of return for utility investors. Problems arise when federal and state utility commissioners and staffs are required to determine the level of investment upon which to base the return, and what constitutes a ‘fair’ rate of return. These topics are discussed in greater detail in Chapter 7, on pricing.
THE BEGINNINGS OF UTILITY REGULATION Utility regulations are the outgrowth of the many state railroad commissions formed after the Civil War to control what was seen as discriminatory pricing practices for shipping and storage of agricultural products. Those early state public utility commissions (PUCs) gradually extended their oversight operations to also control manufactured and natural gas, telegraph and telephone systems, water and wastewater treatment programs, and electric utilities. Today, some PUCs also regulate such diverse services as intrastate transportation, television cable companies, the shipping and storage activities of moving companies, and fuel oil sale and distribution, among other disparate public services. Utility regulation at the federal level began with the Granger laws passed in the late 1800s to provide for interstate public oversight of the nation’s railroads and related services, although it was not until the 1920s and 1930s that government regulation grew in scope to the point where it eventually reached into every aspect of the utility industry. Modern federal regulation of public utilities can be traced to the year 1920, when Congress passed the Water Power Act, after a long and acrimonious battle. The Act set licensing requirements for the development of
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water power and included provisions for improvement of navigation on the nation’s inland waterways. It also established rules for the use of public lands connected with such development. Its chief regulatory provisions, however, result from establishment of the Federal Power Commission. The Commission was given jurisdiction over all construction, operation, and maintenance of dams, water conduits, reservoirs, powerhouses, transmission lines, and other facilities associated with the development, transmission, and use of hydroelectric power. The structure of the Federal Power Commission was streamlined in 1930, with the appointment of a full-time board of five commissioners. The Commission’s jurisdiction applied to all navigable waters and public lands. The Act required everyone wanting to develop a power project to apply for a federal license, which was to remain in effect for a period no longer than 50 years. When it expired, the license could then be either renewed or the property be taken over by the government for its own use. The federal regulatory system grew dramatically under the New Deal legislative program of President Franklin D. Roosevelt. The two pieces of legislation that had the greatest impact on utility regulation by the federal government were the Securities and Exchange Commission Act of 1934 (SEC) and the Public Utility Holding Company Act of 1935 (PUHCA). Most of the regulations that were put in place during that period remain in effect today, although they have, in many instances, been revised extensively.
REGULATION OF THE ELECTRIC POWER INDUSTRY Four federal regulatory actions dealing with electric power were adopted during the 1930s (Gordon 2001). The first two were incorporated into the 1935 two-part law that (1) created federal regulation of wholesale dealings of electricity, and (2) established the PUHCA. This ordered changes in the governance of utilities and gave the SEC control of utility financing. The PUHCA declared that all holding companies of gas and electric utilities were ‘affected with the national public interest because they sell their securities in interstate commerce and use the mails to transact business’ (Glaeser 1953, p. 153). An earlier law, the Securities Act of 1933, gave the federal government jurisdiction over issuance of all securities sold in interstate commerce. The Securities and Exchange Commission was established a year later with passage of the Securities and Exchange Act of 1934. The SEC was established with three main divisions: a Trading and Exchange Division, a Corporation Finance Division, and a Public Utilities Division.
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The third set of actions established federal power supply systems. The two most important of these new federal systems were the Tennessee Valley Authority and the Bonneville Power Administration. The fourth action provided low interest loans to cooperatives for developing power systems in rural areas, thus paving the way for the New Deal’s rural electrification program. Federal regulatory actions during the 1930s also involved the natural gas industry. A new law dealing with regulation of the gas industry was passed in 1938: the Natural Gas Act. The Federal Power Act and the Natural Gas Act expanded federal control over both energy industries by giving the commission power to regulate the rates and service of electric and gas utilities when their transactions are in interstate commerce. The first federal legislation controlling power generation, the Federal Water Power Act, was passed in 1920 to give Congress a measure of control over regional public utility systems and the development of hydroelectric generating facilities. This law also established the Federal Power Commission and gave it jurisdiction over all construction, operation, and maintenance of dams, water pipelines, reservoirs, power houses, and interstate transmission lines. The Federal Power Act of 1935 extended the Commission’s jurisdiction to include control over wholesale power contracts and gave it oversight responsibility for power plant financing (Glaeser 1957; Beder 2003). The 1935 amended law, together with the 1938 Natural Gas Act, thus gave the Commission power to regulate all rates and services of electric and gas utilities when their transactions are in interstate commerce. The Public Utility Holding Company Act of 1935 Prior to the Great Depression that began with the Wall Street Crash of 1929, the public utility industry was highly concentrated, with control in the hands of only a few multi-tiered holding companies. One of the largest of these was the holding company empire formed by Samuel Insull of Chicago. A small number of very large companies owned the controlling stock of other holding companies, which eventually owned one or more operating utilities. The pyramid of holding companies reached absurd heights; in one case the pyramid was six tiers high. The collapse of many of these pyramid empires during the Depression resulted in calls for stiff regulation – with some critics going so far as to call for government ownership of all utilities (Kent 1993). Before the regulatory sweep of the New Deal, controlling utility holding companies was limited by problems inherent in the constitutional division of power between the states and the federal government. Because operating companies tended to serve relatively small, homogeneous
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markets, regulating local utilities was seen as a local problem. As utilities grew, however, operating companies expanded across state lines or acquired operations far beyond their original service areas. To help finance that growth, holding companies were established. As they expanded, regulation remained almost exclusively in the hands of the states or, in some states, even to the municipalities in which the utilities operated. Decisions by the U.S. Supreme Court restricted state utility commissions from regulating holding companies that were engaged in interstate commerce. As a result, the transmission of electricity or natural gas from one state to another was declared to be interstate commerce, which states could not directly regulate. Growth of Holding Companies Utility holding companies were a product of the financial booms of the late 1800s. With cartels and trusts, they were a way of countering the effects of cut-throat competition and of using financial leverage to gain control of vast business empires. In a wave of mergers and acquisitions, holding company empires grew dramatically up until the 1929 crash. In 1926 alone, there were more than 1000 utility mergers. Two related reasons have been given for the growth of the holding company. First, the amount of cash needed to grow by acquiring other companies was greatly reduced. A controlling share of the voting stock was purchased, not the entire company. The purchase was usually made with borrowed money or from the proceeds from the flotation of new stock issues that established the holding company. The assets of the holding companies were the securities of other holding companies. Second, the income gained by the holding company at the peak of the pyramid was far greater than could be gained from operating one or a few utilities. A small number of investors were able to use the holding company concept to leverage the relatively small investments necessary to acquire controlling interest in holding company stock to control very valuable operating companies. Their relatively small investments often earned exceptionally high returns for the holding company investors – often at the expense of a large number of small-holdings operating companies investors. By gaining control of one or more operating companies, they were able to borrow heavily on the operating companies’ assets. They then amplified this financial leverage by using the debt proceeds to finance additional acquisitions – and to pay themselves large dividends. This practice of debt financing became a two-edged sword, however. When sales and profits declined in the 1930s, the return on equity for the holding company dropped significantly, thereby causing much of the industry to collapse like a house of cards after the financial crisis of 1929.
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When several of the nation’s largest holding company empires collapsed after the stock market crash of 1929, subsequent federal investigations uncovered widespread corruption and shady dealings in utility financing, intracompany sales, bribery of local officials, and other unethical activities. These and other problems with the system resulted in passage of the PUHCA. This Act was the most far-reaching federal regulatory legislation to be passed during the Great Depression. The holding company law was designed to eliminate problems associated with the practice of building layer upon layer of holding companies in the electric and gas energy industries. Under PUHCA, any company that owned or controlled 10 percent or more of the outstanding voting stock of a public utility company, or of a holding company of public utilities, had to register with the SEC. Holding companies subject to SEC registration were required to limit their utility operations to a single integrated utility system. The holding company also had to divest itself of any operations that did not functionally relate to the operation of the utility. SEC approval was required for nearly all financial and business activities of registered holding companies. SEC registration had to include copies of the firm’s articles of incorporation, partnership agreements, bylaws, mortgages, underwriting arrangements, and voting trust agreements. Registration also required full disclosure of the firm’s financial structure, names of all officers and directors, any contracts for materials, services, or construction, explanations of bonus and profit-sharing arrangements, and consolidated balance sheets and comparable information (Kent 1993). The SEC was given power to approve only those securities which it felt were ‘reasonable,’ and which were adapted to the firm’s existing financial structure. Approved securities had to reflect both the earning power of the holding company and be shown to be necessary to promote the economical and efficient operation of the utility. Fees and commissions for the sale of securities also had to be ‘reasonable.’ Prior to the 1929 stock market crash, underwriting of utility securities issues had been an extremely lucrative business for a select few investment banking houses, most of which were headquartered in New York. A few underwriters charged fees as high as 50 percent of the value of the issue. For securities to be sold after 1934, the SEC had to be able to establish that the terms and conditions were not detrimental to the interests of the general public, the firms’ investors, or to operating company consumers. Public Utility Regulatory Policies Act of 1978 The Public Utility Regulatory Policies Act of 1978 (PURPA) represented the most far-reaching body of changes to the utility regulatory
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system since PUHCA in 1935. One of the primary goals of PURPA was to ease the nation’s dependence upon foreign energy sources. PURPA required the new Federal Energy Regulatory Commission (FERC) to provide incentives for the development of cogeneration facilities and small power generating facilities (less than 80 megawatts capacity) that use renewable fuels, including biomass, wind power, geothermal, and other fuels. The small and alternative fuel generating facilities named in PURPA are known as ‘qualifying facility’ (QF) generating units and are exempt from certain holding company regulations. In addition to receiving some rate benefits, QFs are exempt from most provisions of the Federal Power Act of 1992 (FPA). For a cogeneration unit to qualify as a qualifying facility, it must produce useful thermal energy as well as electricity. The energy can be used in industrial or commercial processes and for heating and cooling. The output must make up a stated percentage of the user’s total energy consumption and meet established energy efficiency standards. A QF is eligible to receive two major benefits. First, they are exempt from federal and state controls on ownership and from the prices and terms they can charge for their generated power. Second, utilities must purchase electricity generated by a QF at a price based on the utility’s avoided cost, and the utility must sell back-up power to the QF on a non-discriminatory basis. Avoided cost refers to the incremental cost of electricity which, except for the QF, the utility would have to pay to generate the power itself or buy from another source. QFs and a utility can also negotiate rates that are below that of the utility’s avoided cost. Furthermore, as a result of changes to the law made in 1978, any electrical generating operation considered a QF under FERC regulations is not considered to be a utility company under PUHCA rules, and can therefore be owned by a holding company. The Energy Policy Act of 1992 The Energy Policy Act of 1992 (EPAct) provided an additional incentive for developing small generating facilities. These facilities do not have to quality as QFs for benefits if all their produced energy is sold for resale rather than to end users; this type of facility is termed an ‘exempt wholesale generator’ (EWG). EPAct permitted EWGs to own and operate nonqualifying generating facilities, without the units being subject to PUHCA registration and regulation. The incentives for developing small power plants may end soon, however. Congress has been considering repealing the PUHCA, and amending PURPA to limit the rule that requires public utilities to purchase QF and EWG power.
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The Federal Power Act of 1992 Under the Federal Power Act, also enacted in 1992, the FERC was authorized to regulate electricity transmission and the sale of wholesale electric energy in interstate commerce. FERC regulation was expanded to include approval of the disposition of utility property, sales of securities, and regulation of the rates, terms, and conditions for the transmission or sale of electric energy in wholesale markets. FERC also regulates interlocking directorates and imposes a uniform system of accounts and reporting requirements. Three subsequent FERC developments have had a significant impact on the transmission segment of the power industry. FERC issued orders 888 and 889 in the summer of 1996, and order 2000 in December of 1999. Orders 888 and 889 called for the utilities under its jurisdiction to unbundle generation and transmission functions (organizations such as the Bonneville Power Administration and Tennessee Valley Authority are not subject to FERC jurisdiction). Under Order 888, transmission-owning utilities were required to adopt open access and non-discriminatory pricing for their transmission services, including generator interconnection. Order 889 required transmission-owning utilities to publish information about the availability of transmission capacity and make that capacity available to anyone. The orders also set forth operational requirements for a new institution in the system, the ‘independent system operator’ (ISO). ISOs were given the authority to operate the transmission systems formerly operated by vertically integrated utilities. Order 2000 further refined the way the nation’s transmission institutions were to function. The order required utilities with transmission systems (grids) to either enter into an agreement with an ISO, or to join another new organization, a ‘regional transmission organization’ (RTO). The RTO would then control the company’s transmission facilities. Order 2000 also spelled out governance procedures for RTOs. Compliance with the ISO/ RTO directives has been irregular; many state governments have objected to the concept, and have successfully fought divestiture of transmission facilities. The United States is divided into 15 separate regional transmission territories, almost all of which include more than one state. As of 2003, five of the new RTOs were functioning: only the New York, New England, Midwest, California, and the PJM (Pennsylvania, New Jersey, Maryland) RTOs were fully organized and operational (NRRI 2003a). In addition to setting up the ISO/RTO concepts, the FERC attempted to bring order to the transmission sector by introducing what they term a ‘standard market design’ (SMD). The SMD clarifies the rights and obligations
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of owners and users of the interstate transmission grid. The objective of the SMD is to form a set of standard rules for the following purposes: ●
● ●
●
●
●
To allow transmission-owning utilities to develop a revised tariff schedule; To establish a system for allocating transmission capacity; To determine how transmission capacity will be allocated given system constraints; To coordinate system upgrades and allocation of the costs of the upgrades; To allocate costs for constructing special facilities needed to interconnect generators to the grid; And other transmission-related issues.
REGULATION OF THE NATURAL GAS INDUSTRY Despite several decades of successful implementation of deregulation of segments of the U.S. natural gas arm of the energy industry, this sector remains subject to extensive regulation by federal, state, and local governments. More than one federal agency exercises some degree of control over exploration, drilling, and interstate pipeline transmission activities. Government regulation of the natural gas industry began with passage of the Natural Gas Act of 1938 (NGA). This legislation gave the Federal Power Commission the right to regulate interstate sales for resale of gas purchases by pipelines from producers. From its inception, the Commission required that natural gas sales take place under long-term contracts for dedicated reserves. Prices were set by the commission and were based on average production costs in several different regions. As a result, lowest cost producers benefited disproportionately, which in turn provided incentives for all producers to lower their costs, thus driving the price of gas down for everyone. The goal of the Commission was to see that prices remained stable, in line with prices charged ten years earlier. This system remained effective until the 1970s, when energy shocks in 1972, 1974, 1978, and 1980 resulted in price increases of 20 percent per year for unregulated natural gas. Very quickly, price controls on regulated gas caused shortages which, in turn, caused losses by consumers in excess of $23 billion, and producers’ losses greater than $44 billion (MacAvoy 2000). The Federal Energy Regulatory Commission, which replaced the Federal Power Commission, was placed under control of the new Department of Energy. The Commission was charged with coming up with a plan that
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eliminated shortages without causing excessive price increases. Passage of the Natural Gas Policy Act of 1978 (NGPA) was the first salvo in the government’s efforts to deregulate the natural gas industry. Price controls were to be phased out on new production but remained in effect for large segments of the industry. Although the Act identified more than 30 different classifications of natural gas, only three of the classifications were deregulated. The most important of these were new production and high-cost production, types that fell under a larger scheme based on depth and location (on or offshore production). Prices of offshore gas sold after April 20, 1977, were decontrolled. Onshore new gas was decontrolled only if it came from wells 1000-feet deeper than existing wells in the field. The NGPA was part of the plan of the administration of President Jimmy Carter to make the country less dependent upon foreign energy sources. Elimination of controls on wellhead prices – scheduled by NGPA to occur over six years – was seen as a way to encourage greater production. At the time, gas supplies were short and little new exploration was taking place (Schwartz 1975). Gas producers were reluctant to sell gas to interstate pipelines, which were subject to prices controls. Instead, producers targeted sales to nearby intrastate distributors and industrial users that were not subject to federal price controls. A consequence of price controls at the time was a decline in interstate reserves. This, in turn, produced shortages in the industrial Northeast and Far West portions of the country. Many industries moved south to take advantage of uncontrolled gas supplies. Over the first four years after passage of the NGPA, the volume of gas reserves under contract for interstate shipment increased dramatically. Passage of the Fuel Use Act in 1979 restricted growth in industrial usage by requiring power plants to use coal or nuclear fuel instead of natural gas for all new generation capacity. The shortages in the Northeast and Far West disappeared, and the flight of industry to the South ended. Deregulation in the natural gas industry began in earnest in 1985 when the Federal Energy Regulatory Commission took steps to restructure the buyer–seller relationships within the producing, transmission, and distribution portions of the industry. Prior to this time, gas was traditionally sold by pipeline companies to local distributors in a gas-plus-transportation package priced for delivery at ‘the city gate.’ Pipeline companies purchased gas from producers at the wellhead, collected and stored, and, if necessary, processed the gas to remove impurities. The city gate delivery price included the cost of these services.
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The Natural Gas Wellhead Decontrol Act of 1989 FERC Order 436 issued in 1985 was the first attempt to unbundled gas and transportation. Under an open access rule, wholesale buyers and large industrial users of gas could buy their gas directly from the producer, bypassing the pipeline companies. The orders also enabled buyers to purchase space in pipelines for shipment of their gas at published FERC regulated prices. To deal with some still unresolved issues, four years later Congress passed the Natural Gas Wellhead Decontrol Act of 1989. This Act called for removal of all controls on wellhead gas pricing by January of 1993. This meant that gas purchasers could from then on negotiate with producers for the best price possible from any producer. Today, little regulation is exercised over activities that do not involve construction of interstate pipelines. However, interstate pipeline rates, terms, and conditions remain subject to FERC oversight. The Federal Power Act of 1992 gave the FERC jurisdiction over the transportation and storage of natural gas in interstate commerce. At the state and local levels, agencies and commissions regulate drilling, production, and processing activities. Each state has its own licensing, permitting, and bonding requirements, as well as its own system for enforcing local rules and regulations, assessing fines for perceived discrepancies, and for valuing properties for taxation purposes. Pipeline companies were still permitted to follow their old system, and many still provided gas to wholesale customers as they had for years. That system ended completely in 1992, when FERC order 636 took unbundling of the industry to its final position: pipelines from then on could only offer transportation. Transportation prices remained under FERC regulation, however. Pipeline firms offer prices for spot (interruptible), short-term, and long-term space in their pipelines. A result of deregulation of a portion of the gas industry in the 1970s and 1980s, together with availability of gas from new Canadian sources, resulted in an oversupply of gas for most of the 1990s. Prices dropped accordingly. That glut and low prices resulted in many industry conversions to gas from other, dirtier or more expensive fuels, and a major market expansion effort by gas distributors. A new technology developed by the Boeing Company for aviation use – the gas turbine – made it possible to quickly construct small, efficient, gas turbine powered electric generators almost anywhere. Today, gas turbine generators remain the first choice for the addition of peak-period power generating capacity. These developments resulted in a rapid run-up in the consumption of natural gas, so much so that today, a shortage has replaced the former glut. As a result, gas prices increased dramatically over the first years of the
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twenty-first century. Once again gas regulators are looking for additional supplies. The most promising of these alternative supplies is liquefied natural gas (LNG), most of which must be imported. Other alternative fuels being examined include synthetic natural gas and coal gas (Costello and Burns 2003).
REGULATION OF WATER AND WASTEWATER SYSTEMS Other than laws pertaining to water rights, two important pieces of legislation which influence the operations of water utilities are the Federal Water Pollution Control Act of 1972 (more commonly known as the Clean Water Act), and the Safe Drinking Water Act of 1974 (SDWA). The provisions of these laws are managed by the Federal Environmental Protection Administration, with implementation more and more being left to the states. The Clean Water Act The Clean Water Act (CWA) established rules regulating the discharge of pollutants into the waters of the nation. Utilities must file for wastewater and storm water discharge permits for wastewater and runoff at some of their facilities. They must also monitor and control such discharges. In addition, many utilities are required to maintain spill prevention and countermeasure programs. The CWA was passed after the public became alerted to the fact that the nation’s rivers and lakes were rapidly becoming polluted, and that many wetlands were drying up; other irreplaceable wetlands were disappearing under real estate developments. Wetlands came to be recognized as valuable areas that filter and strain harmful pollutants from the water, provide flood control during storms, and provide vital habitat for plants and animals (EPA 2003). Under Clean Water Act rules, individual states are required to monitor the ‘total maximum daily loads’ (TMDLs) of a variety of substances and chemicals in their waterways. In addition, states must ensure that water does not exceed the TMDLs set forth in the Act. Not all states have the ability to comply with these provisions. For those that do not, the EPA is supposed to perform the service. However, because the EPA is also limited in what it can do, this section of the Act usually is not implemented (Bellenger 2002). The Clean Water Act has been modified several times since its passage. A 1981 change improved the capabilities of treatment plants constructed
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under a city grants program. Changes in 1987, however, eliminated the grants program, substituting the State Water Pollution Control Revolving Fund (also called the Clean Water State Revolving Fund), which used EPA–state partnerships to fund projects. A 2003 EPA electronic report, ‘Introduction to the Clean Water Act’, provided the following summary of the Agency’s present CWA regulatory focus: Evolution of CWA programs over the past decade has . . . included something of a shift from program-by-program, source-by-source, pollutant-by-pollutant approach to more holistic watershed-based strategies. Under the watershed approach equal emphasis is placed on protecting healthy waters and restoring impaired ones. A full array of issues are addressed, not just those subject to CWA regulatory authority. Involvement of stakeholder groups in the development and implementation of strategies for achieving and maintaining state water quality and other environmental goals is another hallmark of this approach. (EPA 2003, p. 1)
The Safe Drinking Water Act The objective of the Safe Drinking Water Act was protection of public health by regulating the nation’s public drinking water supply. The law required the U.S. Environmental Protection Agency (EPA) to set national health standards for drinking water to protect against naturally occurring and human-made contaminants. The law has been amended twice, the first in 1986 and again in 1996. The 1996 amendment recognized source water protection, operator training, funding for water system improvements and for public information as important components of a safe drinking water system. SDWA applies to every public water system in the nation. The only systems excluded are those with fewer than 15 service connections or which serve fewer than 25 customers per day for at least 60 days of the year. At the end of the twentieth century, more than 170 000 public water systems fell under SDWA jurisdiction. Most of the regulatory oversight of water systems is carried out by state drinking water programs. States are able to apply to the EPA for ‘primacy,’ which is the authorization to implement and control SDWA programs within their jurisdictions, provided they can show that their standards are at least as stringent as the federal standards. They must also ensure that all their water systems meet those requirements. Only Wyoming and the District of Columbia had not received primacy status by 2000. Water standards are established through a three-step process. First, EPA identifies harmful water contaminants. Second, it determines a maximum goal for each contaminant, below which there is no known or expected risk to health. Third, it specifies a maximum permissible contaminant level for
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drinking water delivered to any customer of a public water system. These levels are enforceable standards and are set as close to the goals as possible. EPA also proposes appropriate treatment techniques. Water utilities must follow EPA standards and provide an annual report of their progress, including measurements of all listed contaminants found in their water supplies (EPA 1999).
STATE PUC REGULATION State regulations occur on four different levels. (1), the states are the only regulators of some business operations, such as business licensing (sometimes referred to as ‘charters’), insurance, workers’ compensation, and occupational licensing, such as for real estate sales; (2), the states share some level of regulation with the federal government. This occurs most often where the demarcation between intrastate and interstate business blurs, such as with telecommunications, some transportation activities, and the public utility industry; (3), state agencies are often the implementers of federal regulation and standards, such as occupational safety and environmental programs, where states are often permitted to seek different ways of implementing federal programs. Finally, (4) the states sometimes share overlapping jurisdictions with the federal government. Examples of areas where this occurs include such programs as consumer protection, advertising regulation, and some financial regulatory programs (Teske 2003). Individual states have long had the authority to regulate the activities of public utilities that operate within their borders. This authority includes power to regulate rates charged and the financial activities of utilities. The federal government also assigned states the authority to implement the regulations set forth by PURPA. Distribution utilities purchase their power from independent producers. Power purchases are thus a part of the utility’s cost structure. Operating costs are a major component in the rates paid by retail consumers. Operating costs are also included in the compilation of the PUC-established rate of return utilities are allowed. Under normal conditions, public utilities pass the cost of purchasing power from an independent power producer, including power purchased from a QF or from a EWG, through to retail customers. However, some state public utility commissions do not always allow full reimbursement to a utility for the purchase of this, often higher-priced, QF power. In one sense, this has negated the objective of the FERC to support development of non-traditional generating facilities. Some states consider QFs and EWGs to be public utilities and subject to state PUC regulation. PUC
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control includes requiring a certificate of public convenience and necessity, and regulation of organizational, accounting, financial, and other corporate matters. States also exercise control over locating and building generating facilities and over the sales of securities and asset transfer.
REGULATION, DEREGULATION, OR RE-REGULATION? For more than 25 years, deregulation has been a preeminent policy in the regulatory, economic, and political environments of businesses both in the United States and abroad (Teske 2003). As a result, less than 6 percent of American business is now affected by some form of direct regulation; in 1975, more than 16 percent of the U.S. economy was covered by government regulation. As the following statement suggests, except for the utility industry, policy has shifted dramatically away from economic regulation of business: The dominant view about much economic regulation over the past 25 years is that it was either a bad idea from the start or a practice that failed over time, except in cases of ongoing monopoly power that required ongoing regulation. (Teske 2003, p. 294)
Since the 1970s, the rationale underlying utility regulation in the United States and elsewhere has been undergoing extensive revision. Efforts to deregulate the utility industry followed a trend toward smaller and less intrusive government, privatization of government owned businesses, and freeing management from many restrictive rules and regulations that seemed to be stifling economic growth. The deregulation movement was brought to a rapid slowdown in 2002 and 2003, however, after problems in California’s deregulation program resulted in alleged price gouging and the bankruptcies of firms like Pacific Gas and Electric (PG&E) and Enron, among others. As a result of this crisis, a number of changes in the way energy markets are regulated have been proposed at both the federal and state levels. A number of states have put their proposed deregulation proposals on hold. Congress failed to pass the Energy Bill in 2003 and 2004. Before California’s experience in 2000, deregulation of the power industry was proceeding rapidly; from 1995 to 2000, fully half of the states chose to deregulate. Since the California and Enron problems, there is great uncertainty in the future scope and scale of utility regulation. The pace of utility deregulation has slowed significantly, as failure to pass the 2003 energy bill illustrates.
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SUMMARY Public utilities are subject to a wide variety of local, state, and federal government regulations. These regulations deal with ownership and governance, raising capital, transactions between company units, environment, the methods of producing utility products, health and safety issues, environmental concerns, and many other aspects of utility operations. As ‘natural monopolies,’ utilities are considered to be legitimately subject to government oversight. Utility regulation at the federal level began with the Granger laws passed in the late 1800s. In the 1920s and 1930s, government regulation grew to where it eventually reached into every aspect of the industry. Modern federal regulation of utilities first appeared in 1920, when Congress passed the Federal Water Power Act. The Act set licensing requirements for the development of waterpower and included provisions for improvement of navigation on inland waterways. It also established the Federal Power Commission, which was given jurisdiction over all construction, operation, and maintenance of dams, water conduits, reservoirs, powerhouses, transmission lines, and facilities associated with development, transmission, and use of hydroelectric power. The federal regulatory system grew dramatically under President Franklin D. Roosevelt. The two pieces of federal legislation that had the greatest impact on utility regulation were the Securities and Exchange Commission Act of 1934 and the Public Utility Holding Company Act of 1935. SEC approval was required for nearly all financial and business activities of registered holding companies. Holding companies required to register with the SEC in this way had to limit their utility operations to a single integrated utility system, while divesting themselves of any operations that were not functionally related to the operation of that utility. One of the goals of the Public Utility Regulatory Policies Act of 1978 was to ease the nation’s dependence upon foreign energy sources. PURPA required the new Federal Energy Regulatory Commission to provide incentives for the development of cogeneration facilities and small power generating facilities (less than 80 megawatts capacity) that use renewable fuels, including biomass, wind power, geothermal, and other fuels. The Energy Policy Act of 1992 provided an additional incentive for developing small generating facilities. Under the Federal Power Act, also enacted in 1992, the FERC was authorized to regulate electricity transmission and the sale of wholesale electric energy in interstate commerce. FERC regulation included approval of the sale of utility property, securities sales, and regulation of rates, terms, and conditions for transmission or sale of electric energy in wholesale markets. FERC also regulates interlocking
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directorates, and imposes a uniform system of accounts and reporting requirements. Government regulation of the natural gas industry began with passage of the Natural Gas Act of 1938. This legislation gave the Federal Power Commission the right to regulate interstate sales for resale of gas purchased by pipelines. Other than laws pertaining to water rights, two important pieces of legislation which influence the operations of water utilities are the Federal Water Pollution Control Act of 1972 (more commonly known as the Clean Water Act) and the Safe Drinking Water Act of 1974. Since the 1970s, the rationale underlying utility regulation in the United States and elsewhere has been undergoing extensive revision; deregulation of the utility industry rather than regulation now dominates policymakers’ thinking. This follows a trend toward smaller and less intrusive government, privatization of government-owned businesses, and freeing management from many restrictive rules and regulations.
ADDITIONAL READING Crew, Michael A. and Paul R. Kliendorfer (1986), The Economics of Public Utility Regulation, Cambridge, MA: MIT Press. MacAvoy, Paul W. (2000), The Natural Gas Market: Sixty Years of Regulation and Deregulation, New Haven, CT: Yale University Press. Wickwar, W. Hardy (1938), The Public Services: A Historical Survey, London: Cobden-Sanderson. Wilson, James Q. (1980), Politics of Regulation, New York: Basic Books.
PART II
Public utility management challenges ‘Management’ can be defined as the art and science of getting things done through people. This means that, in order for managers to achieve their goals, they must plan, organize, motivate and lead others in the organization to complete their tasks. Individual workers, supervisors, and managers are typically organized together into separate functional departments. Each functional activity involves a set of specific skills and tasks that are relevant to that activity alone; they also involve tasks and traits that are common to everyone in the organization. Each function has its own challenges for management. This part of the book looks at some of the chief challenges public utility managers face in the central functions of organization management: planning, leadership, pricing, marketing, information systems, finance and accounting, human resources, and program evaluation. Each of these management functions are exercised in similar ways in the three utility industries – electric power, natural gas, and water and wastewater. However, there are also challenges that are specific to any given industry, including the public utility industry. Every utility organization, whether publicly or investor-owned, must address a variety of challenges that exist in each of the management functions. Examples of how these common and specific functional problems affect management are woven throughout this section.
5.
Meeting challenges in utility planning
Planning in public utilities is carried on at two separate but related levels and for different purposes. Both types of plans are necessary for achieving organization objectives. The most comprehensive level of planning is strategic planning. The purpose of strategic planning is to provide the organization with long-term direction for achieving its fundamental objectives. The second, but typically more specific level, is operational planning. The purpose of operational planning is to effectively and efficiently allocate scare resources for carrying out the work of the organization. Strategic plans usually extend over several years – typically from three to five years. Organizational plans usually cover a one-year period. Upper-level management is responsible for strategic planning – usually under the direction of the chief executive officer and other top officers. Managers and supervisors are responsible for operational planning, sometimes assisted by professional planning staff (Lewis et al. 2001). Strategic planning has three main purposes: The first purpose is to establish the specific markets and environments in which the organization will compete. The second purpose of the strategic plan is establishing the position that the firm wants to hold at some time in the future – its long-term objectives. The third purpose is to identify how the firm proposes to reach its long-term objectives. The how purpose is expressed as the strategies the organization will follow. For example, strategic options that a public utility might take include choosing to either do its own meter-reading, billing, and customer service, or to outsource these and other ancillary services. In another strategic choice, the utility might elect to focus on the delivery of electric power purchased from independent generators at the best possible long-term contract price it can negotiate, depending upon market purchases for day-ahead or peak power needs at competitive market prices. Or, it might decide to purchase its own gas-fired turbine generator for reserve or peak power supplies. Strategic objectives and policy formulation are developed after comprehensive analyses of both the external and internal environments of the utility. Managers examine external and internal factors in a process called SWOT Analysis. This requires managers to thoroughly and 73
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systematically develop and evaluate data on the past, present, and future environments of the organization to identify internal Strengths and Weaknesses and external Opportunities Threats (Pearce and Robinson 1994). Possibly the greatest advantage of conducting a SWOT analysis is that it produces information that is vital for the survival and prosperity of the organization (Bryson 1988). External analysis surveys the economic, legal and political, social, and technological environments in which the utility operates. Internal analysis examines the resources that are available for tactical implementation. From the results of these two comprehensive analyses of the utility’s situation, managers determine which of the external environmental forces have greatest threat potential and which may result in business opportunities. Managers then determine what opportunities to follow and determine what internal resources are available, which can be acquired, and which are unavailable for planned operations. From these analyses, management then prepares a forecast of probable business levels for the current and subsequent years, taking threats, opportunities, resource strengths and weaknesses into account. The strategic and operational plans specify what actions management elects to take in its operational capacity.
DEALING WITH OPERATIONAL CONSTRAINTS Forecasts of future growth are often included in utilities’ annual reports. However, the Private Securities Litigation Reform Act of 1995 requires utility managements to qualify those ‘forward-looking’ statements as being only their ‘best guesses’ of future events. Forward-looking statements are identified by the use of such words as estimates, expects, anticipates, intends, believes, plans, and conditional verbs such as might, should, would, and could. Management is not restricted in the use of such words, but must also include any qualifying statements regarding such forecasts. WGL Holdings, the Washington, D.C., natural gas holding company, identified the following events or circumstances that could cause actual future results to differ materially from forward-looking statements included in its 2002 annual report. The list could service as a good guide for all conducting external analyses in all regulated utilities. ●
● ●
Changes in economic, competitive, political and regulatory statements or developments; Changes in capital and energy commodity market conditions; Changes in credit market conditions and creditworthiness of customers and suppliers;
Planning ●
● ● ● ● ●
● ●
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Changes in relevant laws and regulations, including tax, environmental and employment laws and regulations; Weather conditions; Legislative, regulatory, and judicial mandates and decisions; Timing and success of business and product development efforts; Technological improvements; The pace of deregulation efforts and the availability of other competitive alternatives; Terrorist activities; Other uncertainties.
The reason for utility managers’ concern with their legal and political environments – often called operational constraints – is based on their need to regularly deal with the regulatory actions of governments. Although deregulation has been partially successful in some segments of the industry, such as telecommunications and natural gas, in other segments deregulation still has far to go to achieve its goals. Deregulation, or restructuring, as it is euphemistically called, of the electric power industry has been put on hold as a result of the California experience and collapse of the energy trading industry. Very little deregulation has been tried in the water and sanitation industries thus far. Public utility commissions are as active today as they were before the deregulation movement began in the 1970s. Utilities have long been one of the most highly leveraged industries in the United States. Economic conditions affect interest rates and the ability of utilities to sell long-term bonds. Regulation policy has a major impact upon the operations of a utility. When the strategic plan is developed for a new or restructured organization, it is often referred to as a strategic business plan. When Tampa Bay Water – a wholesale-only water collection and transmission public utility – adopted its first strategic business plan in January of 1999, the situation analysis portion of the planning process included assessments and strategies for implementation in these major aspects of operations (Rogoff et al. 2002): ●
● ● ●
● ●
Predictive and preventive maintenance of operating equipment needs, processes, and schedules; Energy use optimization and management; Automation in the workplace; Management information systems for report-standardization and improved documentation; Activity-based accounting systems for monitoring project costs; Centralized purchasing, standardized equipment and materials, and materials management systems;
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● ● ●
Records management, including document management and improved water-drawing access; Opportunities to expand services and enhance the revenue base; Outsourcing of non-core business functions; Enhance workforce flexibility by greater cross-training and changes in shift configurations, among other steps.
STRATEGIC PLANNING AND STRATEGIC MANAGEMENT Strategic planning is the first step in the process of strategic management. Strategic management has been defined as the set of decisions and actions that result in the formulation and implementation of plans designed to achieve a company’s objectives (Pearce and Robinson 1994). Broadly, the process involves identifying preferred objectives for the organization, developing strategies for meeting those objectives, and selecting a mix of resources to use in a system of related tasks (tactics). The organization’s objectives are typically spelled out in its mission statement. Mission statements include broad statements about the firm’s purpose, philosophy, and goals. The mission statement is a written description of the company’s philosophy. It may include the products or services offered by the organization, what market it serves, information about the belief system or position on ethical behaviors, and its treatment of employees. A primary purpose of the mission statement is to inform and guide organization employees, but it can also inform customers and stakeholders of its operating philosophy (Boone and Kurtz, 1996). The last task is developing an organization profile that identifies its internal conditions and capabilities. Strategic management refers to this task as an analysis of the organization’s strengths and weaknesses. A brief summary statement of the organization profile appears in every investorowned utility’s Form 10-K annual financial report required by the U.S. Securities and Exchange Commission Act of 1934. A number of important differences have long existed between strategic management carried out in publicly owned utilities and investor-owned utilities, although changes underway now in public management are narrowing these differences. The budget process still drives much public agency planning; whereas, plans and objectives drive budgeting in investor-owned utilities. Eadie made note of this difference in the following statement: Formal long-range planning in the public sector has little in common with strategic planning. Rather than looking outward and focusing on organizational
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change, long-range planning has tended to be an extension of the annual operational planning process. This is to say that it starts on the inside and focuses on the projection of current activities into the future, usually for some arbitrary period, say, five years. (Eadie 1999, p. 138)
The experience of Public Utility District No. 1 of Chelan County, Washington, is an example of the long-range planning process in a publicly owned, diversified utility organization. The utility carries out electricity generation, transmission, and distribution operations, and water and wastewater operations. Rates charged for water and wastewater services were not bringing in sufficient revenue to cover operating costs. Because it is publicly owned, the utility is exempt from state public utility commission regulations on rates. However, it elected to hold a series of public hearings before initiating rate changes. The utility raised water and wastewater rates an average of 15 percent in 2001. The rate increase was part of a long-range plan developed after the series of public meetings.
ESTABLISHING A BASE FOR THE STRATEGIC PLAN Utility managers must construct a strong foundation upon which to build their strategic plans. The key activity in this phase of the planning process is establishing the specific mission for the organization. A mission statement is a written statement that explains the way the utility wants to be perceived by its stakeholders. The statement also defines the utility’s scope of operations, its goals, and the strategies it will take to accomplish those goals. The scope of operations specifies the sector or sectors of the industry the utility wishes to serve. It also presents a clear description of the organization’s belief systems, including the moral standards it follows (Boone and Kurtz, 1996). The best mission statements are developed in a democratic process, from the bottom up. The senior manager has the responsibility for setting forth a vision for the organization’s future, but all managers and staff should be involved in the development of the mission statement. One way to accomplish this task is to form cross-functional teams of managers, supervisors and staff personnel in task groups set up just for this purpose. Once the mission is established and integrated into the organization, it frames the ultimate organizational culture. Developing an organization profile is a descriptive activity; it describes for all stakeholders the shape and scope of the organization as it exists at the time of preparing the strategic plan.
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Constructing a Mission Statement Virginia-based AES Corporation (AES) is a large, independent power company with 36 000 employees and assets in excess of $33 billion in 30 countries on five continents. The company operates 160 facilities capable of generating more than 55 gigawatts of power. AES also operates 20 electric distribution companies that deliver electricity to something like 16 million end-use customers. The mission statement in Box 5.1 was prominently displayed on page 1 of the AES 2002 Annual Report.
BOX 5.1
THE 2002 MISSION STATEMENT OF AES CORPORATION
The Company’s goal is to help meet the world’s need for electric power in ways that benefit all of our stakeholders, to build long-term value for the Company’s shareholders, and to assure sustained performance and viability of the Company for its owners, employees and other individuals and organizations who depend on the Company. To achieve this goal, the Company has taken steps to improve performance and achieve excellence in the operation and management of each and every AES business, including the implementation of a compensation system which is dependent, in part, on each individual within AES meeting performance goals and targets. The Company shall continue to be guided by the four shared values that helped shape the Company’s culture: Integrity, Fairness, Fun and Social Responsibility. Source:
AES Corporation, 2002 Annual Report.
Canadian Hydro Developers, Inc. (Canadian Hydro) owns and operates 12 low-impact, run-of-river water and wind electric power generating plants and one natural-gas-fueled generating plant in British Columbia, Alberta, and Ontario, Canada, with several additional plants at various stages of development. The firm ended 2002 with 88.9 megawatts of generating capacity. The company’s mission is encased in the six guiding principles communicated by its chief executive officer, John D. Keating, and president and chief operating officer, Ross Keating: ●
We strive to meet or surpass all legislative, regulatory and other adopted requirements;
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79
We fully integrate health, safety and environmental considerations into corporate planning exercises and operational activities; We strive to continually improve our performance through achieving and advancing health, safety and environmental objectives and targets, including pollution prevention; we undertake all our activities in a manner that identifies, assesses and manages all health, safety and environmental risks; We engage communities, governments and other stakeholders in meaningful dialogue to address health, safety and environmental concerns; and We advance our ideals through implementation of an effective and efficient health, safety and environmental management system. (Source: Canadian Hydro, 2002 Annual Report, p. 6)
Westar Energy of Topeka operates the largest electric utility in Kansas – Kansas City Gas and Electric – and several other unregulated businesses, including Protection One and Protection One Europe, among others. This company’s mission statement (labeled as its ‘vision statement’) was included in the firm’s 2002 Annual Report and is shown in Box 5.2.
BOX 5.2
THE 2002 COMPANY PROFILE OF WESTAR ENERGY
At Westar Energy we are committed to operating a safe, reliable, open and innovative electric utility with uncompromising integrity. We will provide first-class service to our customers, and, given the choice, they will not hesitate to choose us. We will be a friendly, caring neighbor and business partner worthy of trust. Westar Energy will be a thriving, positive environment where employees are proud to work, diversity is celebrated and all are treated with respect. Talent and leadership of all employees will set industry standards of excellence that foster job security. We will be a premier utility investment opportunity. Our financially balanced organization will deliver consistent returns to our investors. By partnering with our communities, Westar Energy will be an outstanding model of civic leadership and environmental stewardship. All of us working together will make Kansas a better place to live! Source:
Westar Energy, 2002 Annual Report.
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Developing a Company Profile Catalytica Energy Systems, Inc. (CES) designs and produces emission control products and systems for the energy and transportation industries from offices in California and Arizona. The CES Company Profile published in the firm’s 2002 Annual Report is displayed in Box 5.3.
BOX 5.3
THE 2002 COMPANY PROFILE OF THE CES COMPANY
Catalytica Energy Systems designs, develops and manufactures advanced catalytic products for the energy and transportation industries with a focus on cost-effective solutions for improved performance and reduced emissions from combustion sources. Our proprietary technologies include the application of catalysts to combustion systems and next-generation fuel processors to mitigate the environmental impact of power generation and transportation systems. We are marketing our first commercial product Xonon Cool Combustion™, a breakthrough pollution prevention technology that enables natural gas-fired turbines to achieve ultralow emission power production. Xonon® prevents the formation of nitrogen oxides (NOx), a primary contributor to air pollution, through a proprietary catalytic combustion process. We are also conducting technology development efforts related to fuel processing for fuel cells and are actively pursuing adaptation of our core Xonon technology to mobile, stationary, and off-road diesel applications. Source:
Catalytica Energy Systems, Inc., 2002 Annual Report.
Artesian Resources Corporation is one of the relatively few investorowned water utility holding companies in the United States. The company serves approximately 68 000 metered customers in a population base of about 226 000, which represents nearly 27 percent of the population of the State of Delaware. Artesian Resources provided the company profile in its 2002 Annual Report shown in Box 5.4. Mason County, Washington, PUD No. 3 is included as an example of a profile of a publicly owned utility organization. The profile published in the PUD’s 2002 annual financial report is shown in Box 5.5. PUD No. 3 is one of two such publicly owned utilities in the county.
Planning
BOX 5.4
2002 COMPANY PROFILE OF ARTESIAN RESOURCES CORP
Artesian Resources Corporation is a non-operating holding company, whose income is derived from the earnings of our four wholly owned subsidiary companies and our one-third interest in AquaStructure, a Limited Liability Corporation whose primary activity is marketing wastewater services. Artesian Water Company, Inc., our principal subsidiary, is the oldest and largest public water utility in the State of Delaware and has been providing water service within the state since 1905. We distribute and sell water to residential, commercial, industrial, governmental, municipal and utility customers . . . We provide services to other water utilities, including operations and billing functions . . . [and] have contract operation agreements with thirteen private and municipal water providers.In 2002, approximately 99.1% of our net income applicable to common stock was attributable to Artesian Water’s service to customers . . .Upon recognition from the Pennsylvania Public Utility Commission as a regulated utility, our other water utility subsidiary . . . began operations in 2002, providing water service to a residential community . . . in Chester County. Other subsidiaries . . . provide wastewater services in Delaware, and ownership of an eleven-acre parcel of land. Source:
Artesian Resources Corporation, 2002 Annual Report.
BOX 5.5
PROFILE OF A PUBLIC UTILITY DISTRICT
Mason County PUD No.3 was established by vote in 1934 and began operations in 1939 under the direction of three elected commissioners.The district’s headquarters are in Shelton, Washington, approximately 22 miles northwest of Olympia, the capital of Washington State. The district’s service area encompasses 567 square miles, most of which is in Mason County. Electric service is provided to 5 square miles in southern Kitsap County, 18 square miles in eastern Grays Harbor County, and 0.00156 square miles in southwestern Pierce County.The district owns and operates 26.69 miles of 115KV transmission lines.
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Challenges to management
During 2002 a project to provide 5.2 MW of generating capacity was completed with the Olympic View Generating Station being put on-line. The district is now a full requirements customer of the Bonneville Power Administration (BPA), taking delivery of power at ten substations. It has 1 593.4 miles of primary (distribution) lines. As of December 31, 2002, the value of the district’s net plant totaled $95 million [and] served 28 678 customers. Gross utility sales and service revenues for 2002 were $37 698,736. Source:
Public Utility District No. 3 of Mason County, 2002 Annual Report.
THE STRATEGIC PLANNING PROCESS The strategic planning process begins with an analysis of both the external and internal environments of the utility. The external environment is the source of threats and opportunities. The internal environment contains both strengths and weaknesses. The process of conducting an analysis of the external and internal environments is called SWOT analysis (Internal ⫽ Strengths ⫹ Weaknesses; External ⫽ Opportunities ⫹ Threats). Assessing the External Environment A number of external factors may have some degree of impact upon the operations of a utility. Among the most important are (1) economic conditions, (2) political trends and the legal constraints that follow political actions, (3) shifts in social trends, (4) changes in the physical environment, and (5) technological innovation. Not all of these environmental factors exercise the same degree of influence over utilities’ operations. However, the social environment is one of the major problems faced by utility managers today. Managers are expected to operate their utility in such a way that conflicts between various stakeholder interests are minimized. Conflicts occur primarily because of changes in public policy toward utilities. Often, changes have been mandated at the federal level, but were not thought out sufficiently before utilities had to adopt them. A particularly painful example of these conflicts occurred as a result of well-meaning changes introduced during the last decade of the twentieth century into the electric utility industry. The power industry was unbundled; competition was introduced in the generating and distribution segments, but not in the distribution industry, where regulation and prior approval on rate
Planning
BOX 5.6
83
THE ENVIRONMENTAL POLICIES OF XCEL ENERGY
As an energy provider, Xcel Energy maintains a delicate balance between meeting customer needs and protecting the environment. The company’s commitment has many components, including major efforts in Colorado and Minnesota to reduce power plant emissions, and an impressive renewable energy portfolio. With almost 480 megawatts of wind power, Xcel Energy is among the leading providers of wind energy in the nation. In 2002, the company was recognized nationally for its mercury emissions research and signed a precedent-setting agreement with the U.S. Fish and Wildlife Service to expand efforts to reduce bird injuries and deaths from power lines. Xcel Energy also finances a wide variety of renewable energy research. Source:
Xcel Energy, 2002 Annual Report.
changes were required. Distributors were not allowed to change their prices to cover the steep increases in the prices they paid for energy. As distributors found themselves forced to seek bankruptcy protection, the State of California was forced to purchase very high-priced power to ensure that customer demand was met. An imbalance was artificially created in the market; utilities’ carefully crafted strategic planning went out the window. State regulators soon realized that a balance must be reached between the need to protect the interests of all those concerned in any way with the organization (its stakeholders), with the need to not sacrifice the fundamental economic or social activity of the organizations that make up the industry. Environmental pressures constitute an on-going threat to utility operations. Emissions, water pollution, visual pollution, species extinction, site clean-up requirements, and similar concerns affect operation of existing facilities and have a major limiting impact upon future production facility locating decisions. An example of the way one utility organization is affected by environmental factors can be seen in the brief statement in the 2002 Annual Report of Xcel Energy of Minneapolis (Box 5.6). Analyse the Company’s Resources A utility’s chief resources are people, money, and facilities – all of which are limited in both public and private utilities. Determining the best use of
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these resources is a management function. Managers must also develop priorities for their use and provide a system for dealing with the competitive conflicts that often occur during the operational planning phase of developing the organization’s strategy. Another important resource consists of the critical skills that are needed to safely, effectively, and efficiently carry out utility services. Electricity and gas are dangerous to handle and often require detailed engineering knowledge for proper design and implementation of service. Managers at many utilities report that they are having difficulty recruiting young engineers. Shaw (2003), writing about the need for utilities to have secure contingency plans in place to protect continuity of service in the event of a crisis, emphasized the absence of needed special skills in the future. A problem that virtually all utilities will have to contend with, according to Shaw, is a shortage of the internal expertise in technical skills. Although outsourcing may be good for the bottom line in the short-term, it has left most utilities that made the decision to outsource with only ‘the barest resources for devising and developing plans for business survival.’ Selecting Long-Term Objectives and Grand Strategies Identification of an overall strategy for the utility occurs during the analysis phase of the strategic planning process. Desired objectives and projections of required service levels are compared with the outcomes of current operations. The gap between the two measurements constitutes the workloads that need to be planned for. The process of reviewing the gap for opportunities and threats is called ‘gap analysis’. The best mix of activities and priorities for carrying out the workloads are determined by the strategies that are to be followed. Pinnacle West Capital Corporation (Pinnacle West) is a Phoenix, Arizona-based diversified utility company with combined assets of approximately $8.4 billion and consolidated annual earnings of more than $2.6 billion. Its subsidiaries generate, sell, and deliver electricity; in addition, they sell energy-related products and services to retail and wholesale customers in the western United States. In addition, the firm develops residential, commercial, and industrial real estate projects. On its web page the company defines its strategic direction as ‘focused on one constant common goal – create value. Value for our customers, our shareholders, our employees, and the communities we serve . . . we create value by producing and delivering safe, reliable energy.’ In order to achieve that goal, Pinnacle West has established seven core strategic objectives:
Planning
1. 2. 3. 4. 5. 6. 7.
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Focus on superior long-term total returns for shareholders; Provide Arizona electricity customers with reliable energy at stable prices; Capture growth opportunities in electricity markets; Actively manage costs and business risks; Maximize the long-term value of assets; Maintain a disciplined focus on long-term goals while remaining agile; Build generation portfolio consistent with our native load, cash flow, and market conditions.
Pinnacle West’s operations are guided by these strategic objectives as management develops detailed long- and short-range plans for the coming year and longer planning horizons used by the company. Operational level managers identify the best mix of resources that will be used to accomplish the objectives, submit their proposals for approval, and implement the approved programs. To accomplish the fundamental strategic objective of meeting all the service demands of its electricity consumers, Pinnacle West’s regulated subsidiary, Arizona Public Service, implemented a growth strategy by adding new state-of-the-art, gas-fired, combined-cycle power generating plants. To meet its objective of continuing to improve the value it provides its customers, Pinnacle West continued its series of electricity price reductions even as it added the new generating capacity. Annual Objectives, Short-Term Strategies, and Budgets In the past, little if anything took place quickly in utilities – other than responding to disasters. Downed power lines, broken water mains, overloaded sanitary treatment facilities, and similar disaster scenarios required – and received – rapid responses. On the other hand, most production and transmission components of utility systems take several years or longer to construct. Changes and upgrades made to installed distribution systems are long-term projects. It can often take months if not years for regulated segments of the industry to bring about changes in their pricing structure, proposed acquisitions, mergers, and other restructuring moves. As a result, preparing annual functional plans and budgets for utilities is often a multiyear process rather than one year at a time. An example of the complexity of converting long-range plans into annual tactical plans can be seen in the federal requirement for energy utilities to develop integrated resource planning. A large portion of utility demand is cyclical and weather sensitive. Cash
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requirements for purchasing additional product supplies reflect these cyclical variations in demand. As a result, short-term, tactical plans and subsequent budgets for utilities take these seasonal variations into consideration. For example, in fiscal year 2002, nearly three-fourths of total annual consumer demand for gas from WGL Holdings, the Washington, DC, natural gas distributor, occurred in the first and second quarters. To meet this demand, the firm’s cash requirements peak in the fall and winter months, when accounts receivable, revenues, and storage gas inventories are at their highest levels. After the winter heating season, many of those assets are converted to cash, which the company uses to pay down short-term debt and acquire storage gas for the next heating season. Gas is purchased from separate gas producers and stored in facilities owned by interstate pipelines. Managing supply purchase and demand distribution requires quarterly plans and budgets, in addition to the annual business plan and long-term strategic plan.
IMPLEMENT THE STRATEGIC CHOICES Implementing planned activities may be the most difficult of all tasks in the strategic management process. Implementing requires the participation of the entire management team, not just a few senior managers (Thompson and Strickland 1996). Each manager must develop answers to such questions as: What needs to be done in my department or unit to implement the strategic plan? What do we need to do to make sure that our objectives are accomplished? In what ways must I coordinate our activities with those of other departments or units? What parts of my unit’s activities are open to regular accomplishment measurement? What new measurement tools do we need to devise? What contingency actions should we take if we exceed or fail to reach performance targets? What needs to be done now, and what can be done later? How much of the supervisory role can be delegated? For execution of the unit’s planned tasks to proceed in an effective and efficient manner, managers should look upon program implementation as a systematic process. Thomas and Strickland identified eight key implementation tasks that must be completed by management regardless of the type or size of organization. The eight steps include: ●
●
●
Begin by making sure the organization is capable of carrying out the tasks necessary to meet the strategic objectives; Build an activity-based budget that ensures the resources needed to carry out those tasks are available when and where they are needed; Establish appropriate operational policies and procedures;
Planning ● ●
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Include provisions for continuous improvement; Install the support systems necessary to ensure that operational personnel are able to carry out their daily tasks; Develop a reward and incentive system tied to performance; Build and reinforce a supportive work environment and organizational culture; Display the leadership needed to keep the work team moving unwaveringly toward accomplishment of corporate, group, and individual objectives, while continuing to support and improve operational procedures.
Evaluate and Control the Strategic Management Process The goal of the control process is to make sure that operational progress meets or exceeds projected goals. There are two parts to this portion of the strategic process: establishing targets and monitoring progress. Managers establish targets during the objectives stage of the planning process. Monitoring progress is done in many ways. However, today a number of organizations are using formal evaluation procedures for this purpose. Evaluation has been defined as the ‘systematic assessment of the operation and/or outcomes of a program or policy, compared to a set of explicit or implicit standards, as a means of contributing to the improvement of the program or policy’ (Weiss 1998, p. 4). Evaluating the success of a program, policy, or activity involves measuring the outcomes resulting from implementation. The evaluator must measure the end results of the program in terms of its contribution to achieving goals and objectives. Other terms for results include contribution, effects, impacts, net results, etc. During the evaluation the manager must ask such questions as: What are the results of our unit’s program or activity? Are our operational programs achieving the objectives that we planned to accomplish? Did any wanted or unwanted side effects occur because of our work, and if so, what impact did they have on other parts of the organization as a whole? In terms of the overall strategic direction of the organization, what are the short- and/or long-term outcomes of our contribution?
INTEGRATED RESOURCE PLANNING FOR UTILITIES The Energy Policy Act of 1992 (EPAct) introduced a requirement for all electric utilities to begin a planning process for integrating new generating capacity, power purchases, energy conservation and efficiency,
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cogeneration and service area heating and cooling applications, and renewable energy resources. The process is called ‘integrated resource planning’ (IRP); the law became effective on May 1, 2000 (Energy Information Administration 2000). In many ways, this new IRP planning process mirrors many of the features of traditional strategic planning. The goal of the IRP planning process is to ensure that adequate and reliable service is provided to the utilities’ customers at the lowest system cost. This comprehensive planning process forces the utilities to consider necessary features such as diversity, reliability, dispatch ability, and other risk factors that might affect system operation. Furthermore, utilities must take into account their ability to verify energy savings that they can gain through energy conservation and efficiency, together with the projected durability of the savings over time. According to the Western Area Energy Administration – a five-state transmission grid organization – the IRP process resolves demand and supply resource questions in a consistent and integrated procedure (Western Energy Services 2003). Integrated resource planning is the government’s attempt at introducing common planning processes and procedures into the operations of customers of the grid with long-term, firm-delivery contracts. In a firm delivery contract, utilities agree to provide these customers power even when supply shortages require curtailment of service to customers with interruptible service contracts. Prices for firm-delivery contract power are usually much higher than for interruptible-contract power. Power customers are distributors of electricity to residential, commercial, and industrial customers. IRPs must consider electrical energy resource needs and may consider, as an option, water, natural gas, and other energy resources as well. All purchasers of power supplied by the grid must satisfy the following EPAct requirements in their IRP plans: ●
●
● ●
●
● ●
Provide an identification and comparison of all practical energy efficiency and energy supply resource options; Develop an action plan (a tactical plan) covering a minimum period of five years, describing specific actions the firm will take to implement its IRP; Designate least-cost options available to the customer firm; Describe the efforts taken to minimize adverse environmental effects of new resource acquisitions; Schedule public hearings to provide the opportunity for public participation in the preparation and development of the IRP; Conduct and include in the plan, load forecasts; Come up with methods for measuring and validating predicted performance to determine whether objectives are being met.
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Integrated Resource Action Plans and Measurements Every IRP must include a comprehensive body of action plans and an annual progress report. Action plans are the short-term, tactical plans discussed in the section of strategic planning. Action plans include the time period covered by the plan. When the time period expires, the IRP must be revised and resubmitted. The action plan must include: (1) the actions the customer proposes to take to accomplish the goals it includes in the IRP; (2) periodic measurement dates (milestones) for evaluating actions as they are implemented; and (3) the estimated energy and capacity benefits expected to accrue from each action planned. Related to action plan milestones is the requirement for identifying and briefly describing the customer’s proposed measurement strategies. Progress in implementing the resource options adopted by the customers must be measured regularly to determine whether the objectives of IRP are being met.
SUMMARY Planning in public utilities is carried on at two separate but related levels and for different purposes. The highest level of planning is strategic planning. The second major type of planning is referred to either as operational or tactical planning. The strategic plan is typically the responsibility of senior management; tactical plans are developed and implemented at the operational level. The strategic planning process involves identifying objectives for the organization, developing strategies for meeting those objectives, and selecting a mix of resources to use in a system of related tasks (tactics). The first two tasks are closely related: the first is to say what the company does; the second is to say what the organization is. The organization’s objectives are typically spelled out in its mission statement. Mission statements include broad statements about the firm’s purpose, philosophy, and goals. The mission statement is a written description of the company’s philosophy. The organization profile identifies its internal conditions and capabilities. Strategic management refers to this task as an analysis of the organization’s strengths and weaknesses. A brief summary statement of the organization profile appears in every investor-owned utility’s Form 10-K annual financial report required by the U.S. Securities and Exchange Commission Act of 1934. A number of important differences have long existed between strategic management carried out in publicly owned utilities and investorowned utilities, although changes underway now in public management are
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narrowing these differences. The budget process still drives much public agency planning; whereas, plans and objectives drive budgeting in investorowned utilities. A number of external factors impact the operations of a utility. Among the most important are (1) economic conditions, (2) political trends and the legal constraints that follow political actions, (3) shifts in social trends, (4) changes in the physical environment, and (5) technological innovation. A utility’s chief resources are people, money, and facilities – all of which are limited in both public and private utilities. Determining the best use of these resources is a management function. Managers must also develop priorities for their use, and provide a system for dealing with the competitive conflicts that often occur during the operational planning phase of developing the organization’s strategy. Another important resource consists of the critical skills that are needed to safely, effectively, and efficiently carry out utility services. Identification of an overall strategy for the utility occurs during the analysis phase of the strategic planning process. Implementing planned activities is possibly the most difficult of all tasks in the strategic management process. Implementing requires the participation of the entire management team, not just a few senior managers. The control process is designed to make sure that operational progress meets or exceeds projected goals. There are two parts to this process: establishing targets and monitoring progress. Managers establish targets during the objectives stage of the planning process. Monitoring progress is done in many ways. However, today a number of organizations are using formal evaluation procedures for this purpose. The Energy Policy Act of 1992 introduced a requirement for utilities to begin planning for integrating new generating capacity, power purchases, energy conservation and efficiency, cogeneration and service area heating and cooling applications, and renewable energy resources. The process is called ‘integrated resource planning’; the law became effective on May 1, 2000. Every IRP must include action plans, environmental impact evaluations, and progress measurement schemes.
ADDITIONAL READING Berrie, Tom W. (1993), Electricity Economics and Planning, London: Peter Peregrinus. Bolet, Adela Maria (ed.) (1985), Forecasting U.S. Electricity Demand: Trends and Methodologies, Boulder, CO: Westview Press. Joskow, Paul L. and Richard Schmalensee (1983), Markets for Power, Cambridge, MA: MIT Press.
6.
Utility management and leadership challenges
Skilled, knowledgeable management may be the most important asset and scarcest resource that any utility has; it must be used wisely and revitalized regularly. Existing management must provide the environment and conditions under which future good management will be available when it is needed (Farris and Sampson 1973). This chapter is a brief introduction to some of the more important principles of management that future utility managers, external directors, and new commission members need in public service management. It includes the definition of management used in the discussion, a description of the public utility operating environment within which managers work, and provides an overview of the key constraints and universal principles that guide managers in carrying out their tasks. Typically, two paths to senior management have been followed in utilities. One is the engineering side of the business; the other is the professional management path. There is no single best path to follow and no one best way of recruiting future utility managers. Engineers typically benefit from additional education in management; business management professionals often need additional education in the technical aspects of the utility. All utilities – large and small, energy, water, and sanitation – have need for both types of managers. Equally, there is no one best way of developing future utility managers. One school of thought suggests that potential future managers should be allowed and encouraged to extend themselves as much as possible, even at the risk of failure. Stellar performers must not be held back by organizational inertia or seniority rules.
WHAT IS ‘MANAGEMENT’? The term ‘management’ is used to mean several different things. For some, management is closely associated with the concept of leadership. Others see it as just a different word for administration. Still others use the word to mean supervision; that is, management is supervising people who do the work of the organization. In this text, the term ‘management’ is used to mean ‘the set of guiding activities taken by human actors to help others 91
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Challenges to management
accomplish the many objectives of an organization.’ Public utility managers apply these activities to accomplish objectives in organizations engaged in providing a public service, including managing all actions relating to the organization’s franchise granted by some public body. Management in public utility organizations includes elements of government management, public administration, and management in unregulated business (Bozeman and Straussman 1991). Public management is management under political authority; it is subject to public accountability, shared power, and attention to political influence. Public authority is manifested in the number and types of laws affecting industry operations that are passed each year, the political philosophies of elected public officials, and the attitudes and opinions of public managers who are appointed to administer rules and regulations. Public administration has traditionally been bureaucratic management. The bureaucratic model of government proposed by Max Weber in Germany and Woodrow Wilson in the United States was built upon the following characteristics: ● ●
●
●
●
Control within the organization was centralized and hierarchical; Manager and worker performance was guided by rules and administrative regulations that tended to be fairly stable and exhaustive – a place for everything and everything in its place; Services to the public were standardized and impersonal; everyone received the same treatment; Internal staffs handled all operations; no outside contractors or private providers existed; Staff members were chosen by competitive examination, not subjective criteria.
Modern public management is similar to business management in many ways. Although all businesses are subject to legal constraints such as business taxation, antitrust legislation, prohibition of false advertising, avoidance of price discrimination, and similar generic legislation, private businesses are not subject to political authority. Provided they comply with the laws that apply to all businesses in their industry, managers of private business are subject to little direct governmental regulation.
THE UTILITY MANAGER’S OPERATING ENVIRONMENT The operating environment of public utilities includes portions of both private and public management. Managers in utility organizations use
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management practices that are similar to, if not identical with, the fundamental management principles that are used in all organizations. It is important to remember that many differences do exist, however. Osborne and Plastrik identified a number of these differences in Banishing Bureaucracy, their 1992 follow-up volume to the landmark Reinventing Government. Making changes in government organizations requires greater political effort. In their opinion: Perhaps the most profound difference is that private organizations exist within larger systems, or markets, that are generally fairly functional. Most private, for-profit organizations have clear missions, know how to measure their bottomline performance, face competition, experience very real consequences for their performance, and are accountable to their customers. . . . In government, most organizations exist within fairly dysfunctional systems. Many organizations have multiple (sometimes conflicting) missions; few face direct competition; few experience consequences for their performance; few have clear bottom lines (few even measure their performance); and very few are accountable to their customers. (Osborne and Plastrik 1992, p. 12)
The bleak picture of public organizations painted by Osborne and Plastrik more than a decade ago does not accurately describe today’s complex public utility industry, if it ever described the industry at all. Restructuring and reorganization have interposed market competition upon the once monopolistic utility-industry structure. However, managing utilities has always required an absolute need to gain, monitor, and attempt to influence, political authority to operate. Much of the industry still functions under conditions of monopoly and does so by franchise granted by some governmental body. The implication is that franchises, once granted, can also be rescinded. Two key factors which distinguish the majority of the utility industry from other economic endeavors are: (1) elements of the utility industry operate under socially sanctioned conditions of monopoly competition, and (2) one or more elements of the organizations’ operations or supply chain are regulated by one or more levels of government. U.S. laws require that regulated businesses be managed in ways different in many respects from that of the nonregulated businesses. For example, management decisions in regulated businesses are often subject to public oversight at public utility commission hearings. Public policy and public opinion expect different conduct in many managerial matters, including the setting of prices, the mandate to meet all service-area demand, and restrictions on allowed operating profits, among others. Because public utilities provide essential public services that are considered to be endowed with a public interest, utilities management requires
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both public and private sector management knowledge. Market economies must often balance conflicting social and private interests. This is paramount in the utility industry, where there exists a variety of conditions under which economic activities take place. At one end of the range of conditions are the privately owned, nonregulated businesses that range in size from General Electric and General Motors to the independent corner grocery store. At the opposite end of this continuum are the government-owned organizations such as the U.S. Post Office, Tennessee Valley Authority, and Bonneville Power; extreme examples at this pole include the nationalized industries that were often found in many third-world countries, the Soviet bloc of nations, and socialist economies such as were found in Great Britain, Sweden, New Zealand, and others. Municipally owned and operated utilities are nearer to this tradition of public ownership. Somewhere between the opposite poles of this economic continuum are free-enterprise businesses such as banks, investment brokers, and insurance companies that are subject to varying degrees of special economic regulation. Also in this group are the privately owned public utilities; these have been on the receiving end of the most complete government regulation of any industry in the group. These regulated industries are a diverse group of public service organizations ranging in size and scope from multinational, vertically integrated energy corporations to local water and power cooperatives. These utilities have been subject to government regulation at either the federal, state, or local, or all three levels at once. Most energy utilities are privately owned businesses – commonly referred to as investor-owned utilities. On the other hand, local governments own most of the nation’s water, wastewater, and sanitation utilities. These governments may operate the utility themselves, or they may contract with private operators for the day-to-day operations; in either case, the government utility may also contract with private firms to perform their billing and customer service functions, among others. Management of public utilities differs from the administrative management that once characterized most government bureaucracies, government regulated utilities, and nonprofit organizations. Public utility management today can be said to incorporate a mix of traditional dedication to public service that is being increasingly tempered by the entrepreneurial, marketoriented managerialism identified as the ‘New Public Management.’ This trend will be discussed in greater detail in later chapters. In terms of ownership or governance, the public utility industry is a diverse mix of public, private, and cooperative ownership. Utility management includes elements of managing in both the public and private sectors. Organizations in the utility supply chain often find themselves operating in
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both profit and not-for-profit economic environments. As a result, discussion of the functions and processes that make up utility management is often more theoretical rather than descriptive (Farris and Sampson 1973). In discussing management in the past, more emphasis has been placed upon ‘what ought to be’ or ‘what could be’ than upon ‘what is.’ In this book, the focus is the reverse; greater emphasis is upon ‘what is’ in the industry.
UNIVERSAL MANAGEMENT FUNCTIONS Utility managers operate within a dynamic environment that is loosely anchored in the shifting policy sands of the political, economic, environmental, and social environments of the time. Policy shifts have tended to be cyclical, occurring something like every ten or 30 years. In addition, every generation of managers discover and apply new tools to guide them in the conduct of their managerial tasks. For example, in the 1970s, ‘management by objectives’ (MBO) was eagerly adopted by organization managers. ‘Total quality management’ (TQM) came to the fore in the 1980s along with other management tools that were so effective in Japan. In the 1990s, value chain management, learning organizations, and strategic planning were important concepts added to the manager’s tool kit. Fortunately, many of the fundamental principles of management appear to have always been applicable, and are as useful today as they were when they were first introduced. At the beginning of the twenty-first century, utility management has seen adoption of performance-based management procedures, privatization, contract services, and market-based competition, among others. Among the universal management principles are these basic functions performed by all managers: analysing, planning, organizing, directing (leading), and controlling the decisions made to enable the utility to accomplish its objectives. Analysing for Management Decisions Management analysis is the ability to locate, examine, evaluate, and interpret meaningful data for the purpose of making a management decision. The first step in any planning process, for example, is conducting a comprehensive analysis of the factors contributing to the present situation. Before any objective for future operations can be formed, planners must have a thorough picture of the existing state of affairs. In performance measurement, this process is sometimes referred to as ‘benchmarking,’ and includes comparisons with best example operations.
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Analysis is both a skill and an art; it requires knowledge and creativity. Managers need to have an understanding of the greater economic system, the social and cultural trends that shape the industry, and the structure and scope of the utility industry. They also need to know when and how to use management principles and tools. This requires knowledge of economic theory, quantitative and qualitative analysis techniques, principles of business administration, and the use of analytic and forecasting computer software. Interpreting theory and data, however, is a matter of judgment, which is where the art of analysis comes into play and which is best learned by following the example of one or more effective leaders.
THE ART OF FORECASTING One of the chief products of meaningful analysis in utilities management is the ability to make valid forecasts. Utility forecasting is the process of determining, with some acceptable degree of reliability, some future state of affairs relating to the organization. Although no individual forecast can be completely accurate, the ability to make good forecasts is critical for all future utility operations (Farris and Sampson 1973). The legal and economic constraints of public utilities make reliable forecasting and good planning more important for public service organizations than for other businesses. Utilities are legally required to meet all demands for their products or services whenever it is needed. As a result, most utilities invest in some excess capacity, or they must resort to making spot purchases of high-priced supplies at periods of peak demand. Utilities use demand forecasts to avoid problems of under-supply or excess capacity. Skill in analysis is what makes it possible for a utility manager to construct a five- or ten-year forecast of future investment requirements from a series of predicted growth patterns in the service area, economic conditions, climatic changes, employment projections, and other, related economic and social data. Utility managers often use simulations as a tool for analysing the organization. Brandon Owens (2003) described a financial performance simulation to first evaluate profitability of a new gas-fired, combined-cycle electric generator unit, and then to apply those performance results as a benchmark used in his wider prediction. Owens used the cost and performance characteristics of the new unit in all regions of the country. He used the simulation as a way to gauge the health of the generation segment of the entire electricity sector. The results of the simulation permitted him to predict that some power markets will begin to recover by 2006, and that the Southern California market would be the first to do so.
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The Management Planning Function As we saw in Chapter 5, utility planning operates on two levels: (1) the formulation of strategy, and (2) the selection of operational tactics appropriate to the strategy. Strategy is typically established at the formative or senior management, level; tactics consistent with the strategy are developed and applied at the operational level. Objectives and policy formulation is based primarily on comprehensive analyses of both the internal and external environments of the utility. Internal analysis examines the resources that are available for tactical implementation. External analysis surveys the economic, political, social, and technological environments in which the utility operates. Managers who formulate strategy in investor-owned utilities usually are corporate directors and/or principal executives, all of whom are responsible to stockholders. In publicly owned utilities, strategy is typically formed by elected or legislatively appointed officials, municipal or district administrative commissions, senior-level civil servants, top administrators, or professional public service managers. At the strategy formation level, management’s functions are, first, to establish overall goals or objectives of the organization, and second, to establish general policies designed to meet these goals. At the administrative or tactical level, managers employ four processes: (1) they forecast future resource needs of the organization, (2) make plans to meet those needs that are based on forecasted customer demands, (3) acquire and organize the necessary financial, human, and physical resources necessary to carry out the plans, and (4) develop and apply appropriate performance measurement and control procedures. The actual use or supervision of these resources requires constant checking to assure that the best possible use is being made of existing resources, while continuing to study possibilities for obtaining even better performance by varying the mix of resources. The Organizing Function of Management Organizing is the process of bringing all the needed resources of the utility – money, people, facilities – together when and where they are needed to ensure accomplishment of the utility’s objectives. Managers use both short- and long-range forecasts for this purpose. The important thing to remember about organizing is that it is a team activity involving representation from all chief functions of the organization. A change in any one of the chief resource elements has a direct impact on the others. Closely related to the organizing function are reorganization and restructuring. Reorganization refers to current changes made in the allocation
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or distribution of resources. It involves operational and structural changes in the organization. For example, changing economic conditions may require a utility to revise its growth projections upward or downward. Differences in demand forecasts resulting from changing economic conditions often requires organizational changes which more accurately reflect the state of reality, such as adding or reducing staff, mothballing or building new generating plants, or locating additional sources of water or natural gas. Restructuring, on the other hand, refers to broadly based, long-term changes in either an industry or an organization. Restructuring often involves changes in the mission or grand strategy of the utility. For example, in response to lower than expected revenues, higher than expected costs, and critical shifts in the economic environment of its international electricity operations, the AES Corporation of Arlington, Virginia, set up a Restructuring Office in 2002 to focus on improving the operating and financial performance of the firm. The office was given responsibility to evaluate prospects for its underperforming businesses, make changes where deemed appropriate, and sell or abandon others. A similar reorganization was recently carried out by CH Energy Group, a utility holding company that controls the regulated Central Hudson Gas & Electric Corporation. Central Hudson provides public utility electric and gas services to an area with a population of approximately 662 700 living along the central Hudson River north of New York City. The purpose of the reorganization was to streamline administration and improve management effectiveness in nonregulated, competitive portions of its business. The program involved merging some businesses into others, selling others, and other organizational actions. The utility industry overall is undergoing restructuring as a result of government regulatory changes. Restructuring in this case involves ‘unbundling’ the components of the old vertically integrated, regulated utility industry into separate generation/production entities, transmission organizations, and independent local distributors of utility services. Restructuring of the industry in this way is referred to as deregulation. The goal of deregulation is to replace existing government regulation with market controls in order to lower the price consumers pay for utility services. Restructuring has worked well in the natural gas industry, not as well in the electricity industry, and as yet, has not been tried to any degree in the water, wastewater, or sanitation industries. While the water, wastewater and sanitation industries remain largely municipally owned, a growing number of cities have elected to privatize some or all of their utility operations. The city maintains ownership, but contracts with outside suppliers for the operation of those systems.
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The Directing Function of Utility Management Directing the operations of an organization is another of the fundamental activities of management. Managers manage people. The chief function of management is to assure that the organization is able to perform its basic functions – the supply of desired goods or services to customers at reasonable prices – while also protecting the various interests of its employees, investors, and affiliated groups. Responsible management must plan for and deal with the individuals, teams, and groups which together make the organization what it is. For managers to be able to make this happen, organizations must maintain a dependable system of policies, procedures, conditions, motivations, and rewards. The tasks necessary to achieve the goals and objectives of an organization are shaped by the organization’s formal and informal policies and procedures. Organization effectiveness depends on the way that leaders, managers, supervisors, and workers are motivated to subsume their own objectives to those of the organization. In his small volume on leadership and organizational renewal, Burt Nanus (1996, pp. 4–5) defined a leader as ‘a person who marshals the resources of an organization – the people, capital, and technologies – to move it in the right direction.’ By ‘right direction,’ Nanus meant operations that ensure future success, growth, and viability of the organization. The leader functions as a change agent, influencing or making choices about investments, personnel, markets, if and with whom to arrange partnerships, and which new directions or businesses to enter. Finally, he described a leader as ‘the chief coach and mentor,’ the manager who ‘creates hope and high expectations, acts as a teacher, learner, facilitator, role model, and friend to those who do the actual work of the organization.’ Leadership skills are needed for success in dealing with people. Leading means guiding and motivating managers, supervisors, and employees in actions to achieve organizational objectives (Boone and Kurtz 1996). Hodgkinson (1983) identified four key laws of leadership: know the task, know the situation, know the group, and know yourself. The laws and questions to ask yourself as you develop leadership skills are presented in Box 6.1.
BOX 6.1 1.
HODGKINSON’S FOUR LAWS OF LEADERSHIP
Know the Task What is the mission of the organization? What are the factors that contribute to the mission?
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How are they expressed? How are they coordinated in the organization? What is my role in accomplishing the mission? 2.
Know the Situation What significant and most prominent features of the environment are threatening to keep the organization from accomplishing its tasks? Which of these need special attention? Which can be ignored? How is my contribution affected by the situation?
3.
Know the Group What do I need to know about the group? [You can never know too much!] In principle, there is no upper limit to human accomplishment. What, then, stands between superior achievement and minimal achievement?
4.
Know Yourself What, if any, are the boundaries of my obligation to the organization? Do I have the requisite capabilities to achieve my maximum potential? What is my capacity for dealing with uncertainty? Above all, what are my weaknesses, and how can I turn them into strengths? Am I able to cope with adverse emotion – anger, frustration, fear, hatred, envy, resentment, greed – in ways that serve as examples to others in the organization?
Source:
C. Hodgkinson, The Philosophy of Leadership, 1983, p. 211.
The Controlling Function of Utility Management Controlling is the management function that (1) establishes standards of performance, (2) facilitates monitoring and evaluating performance, (3) weighs actual performance against planned standards or targets, and (4) institutes changes where needed and reinforcement where performance meets or exceeds targets. As they guide organization’s operations, managers are concerned with two groups of questions (Pearce and Robinson 1994). The first set deals
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with strategy; the second set is concerned with performance. By analysing the operating environment and performance of the organization, managers ask such questions as: ● ● ●
●
●
●
Is the utility moving in the right direction? Are the critical success factors present? If the utility operates in a competitive environment, does it have a maintainable competitive advantage? Are management’s assumptions about major trends and changes upon which utility strategy is constructed correct? Is management doing the critical things that need to be done, when they need to be done? Should the strategy be changed, fine-tuned, or dropped entirely?
Performance questions involve measuring performance against established, measurable objectives. Examples include the following: checking to see that schedules are being met, and determining whether financial objectives for revenues, earnings, cash flows, debt servicing, and other financial targets are being met.
UTILITY MANAGEMENT CONSTRAINTS A manager’s freedom of movement to initiate change is limited by certain constraints or limitations. Two broad classes of constraints limit management action: external and internal constraints. It is essential that managers at all levels identify and understand these environmental limitations; doing so is one of the first steps in the utility’s strategic planning and management processes. Perhaps the five most important external environmental constraints on public utility management are, in order of importance, profits, regulatory laws, general laws, public opinion, and social factors. Internal constraints tend to be resource related, although organizational culture may also have a limiting effect upon management’s actions. Profit Constraints Profits are a major goal and motive for privately owned utilities, whether regulated or nonregulated. Profits are a major constraint because no privately owned business can indefinitely maintain or attract the capital resources necessary to continue its services, or to expand or improve its services without profits. Profits are used to pay dividends to the utility’s owners
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(investors) and to gather the retained earnings that pay for future expansion and for funding contingency actions. Economic reality demands that a privately owned business be profitable in the long term if it is to survive. A nonregulated business can build up reserves, but a regulated utility may not be able to do so. Therefore, regulated utilities are often highly leveraged. They turn to bonds and securities markets to fund capital improvements. In such cases, cash flow must be sufficient to fund current operations and service. Public utility commissions have not always been receptive to the idea of including plant-expansion debt service in rate revisions. Regulatory Constraints The utility industry has for many years been one of the most tightly regulated industries in the world. Utilities provide services that are deemed to be critical for modern life. When the large electric light and power holding companies collapsed after the stock market crash of 1929, many citizens and legislators felt that the companies took advantage of their monopoly positions, and therefore needed to be brought under strict federal regulation. The Democratic Party platform for the election of 1932 singled out the electric power and light industry as the target for the proposed regulation. Prior to the 1920s, most public utilities were operated locally and if regulated at all, were regulated at the local level. Congress established the Federal Power Commission in 1920, but at the time its power was limited to conducting investigations. In 1928, a Federal Trade Commission investigation of the pubic utility industry found that something like 75 percent of the industry was controlled by a few holding companies. In 1935, Congress enacted the Wheeler–Rayburn Act, more commonly known as the Public Utility Holding Company Act. The Act limited the number of separate company levels that could be owned by a holding company. It also required public utility holding companies to register with the Securities and Exchange Commission, established rules for issuing utility company securities, and established regulations for asset acquisitions, intercompany transactions, and service contracts between operating and parent holding companies (Clough and Marburg 1968). Regulation at the state level generally preceded federal level regulation. State regulation took the form of the establishment of public utility commissions. Commissioners, operating under state legislative guidance, issued operating certificates, granted licenses and issued franchises, set territorial limitations to utility service areas, restricted the number of businesses a utility company could acquire, established rules for rate determinations,
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set common accounting standards, and set allowable rates of return on investments for operating utilities. Today, utilities are a mix of regulated and unregulated businesses. While some regulatory constraints have been lifted, others have appeared to take their place. The federal government has mandated restructuring of the industry, subjected certain segments to market competition, and forced other utilities to divest portions of their vertically integrated operations. The most heavily regulated segment of the utility industry at the beginning of the twenty-first century are the local distribution companies. Deregulation seems to be creating as many or more new regulations as it is eliminating others. Legal Constraints All businesses must comply with general laws of society in which they operate. Utility businesses operate in a more restrictive environment than do most other businesses, such as being affected by many special regulatory limitations or requirements on such matters as profits, pricing, operating rights, service performance, financing, and the like. Many of these laws conflict with one another. Examples of the types of legal actions and constraints faced by public utilities can be seen in the list of legal proceedings discussed in the Maine Public Service Company’s (MPSC) 2002 Annual Report (MPSC is a utility holding company that owns all of the common stock of Maine and New Brunswick Electrical Power Company and other subsidiaries). A sample of the proceedings includes (1) a complaint by a competitor alleging that actions of MPSC employees resulted in the firm’s competitive electricity provider receiving a competitive advantage over competitors by Maine Public Utility Commission (MPUC) decisions; (2) disagreements regarding including possible changes to the annual charges of $12.5 million for recovery of stranded costs (stranded costs result from unbundling of vertically integrated utility systems); (3) an investigation by the MPUC regarding the design of transmission and distribution rates; (4) request for approval by the MPUC of the firm’s proposal to reorganize the company into a holding company structure; (5) a request to the MPUC for approval of an alternative rate plan; and (6) an MPUC inquiry into the status of the competitive market for electricity supply in Northern Maine. Public Opinion Constraints Utility managers are by necessity very sensitive to public opinion. Managers have long considered maintaining a good public image an important success
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factor, particularly in the regulatory environment in which most utilities must operate. Negative public opinion can have a direct impact on bottom line results by failure to secure needed rate increases. As a result, decision makers generally are careful to avoid making decisions or actions that adversely affect the reputation of the organization. Managers in investorowned utilities must be aware of the potential threats of public ownership, public competition, loss or cancellation of franchises, enactment of more stringent regulatory legislation, or more stringent enforcement of existing legislation. On the other hand, yielding to the pressures of public opinion can be quite costly and conflicts with the need to maintain adequate profits. Examples include yielding to demands for less visual pollution. Clearly the free-wheeling days of almost unlimited entrepreneurial or managerial freedom and flexibility are only a historical memory. Social Constraints Utility managers long ago learned that their organizations do not exist exclusively for the benefit of government administrators, owners, managers, employees, financiers, or suppliers. Certainly all these groups and others have legitimate economic, legal, or moral interests in a business, but these interests are subservient to overall customer and social interests. A major course of social constraint today is pressure upon operations brought about for reasons related to the environment. Social environmental constraints, both legal and extralegal, affect the amount, rate, and direction of growth. They affect the siting of power generating facilities, as well as transmission lines and gas pipelines. They have forced removal of dams on rivers and streams, and severely restricted the development of waste water treatment facilities and solid waste earth fills. The high capital cost of construction of nuclear generation plants is largely due to the public’s environmental concerns. This high cost concern over plant safety and disposal of spent nuclear fuel has all but eliminated construction of new nuclear power generating plants – despite the fact that nuclear generators are still the lowest cost producers of electricity (Numark and Terry 2003).
CRISIS MANAGEMENT AND TERRORISM PROTECTION Disasters such as the terrorist attacks on September 11, 2001, the failure of Enron and the California energy reorganization process in 2000 and 2001,
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and the electric power grid failure in August of 2003, have all contributed to making crisis planning and management a major concern of utilities managers. An organizational crisis has been defined as follows: An organizational crisis is a low-probability, high-impact event that threatens the viability of the organization and is characterized by ambiguity of cause, effect, and means of resolution, as well as by a belief that decisions must be made swiftly. (Pearson and Clair 1998, p. 60)
Among the variety of different disasters that can result in a crisis for a public utility are fires and floods, droughts, snow or ice storms, downed power poles, broken water mains, back-up sewage systems, electricity blackouts, and terrorist activities. Today, utility managers are also facing a financial crisis in finding funds to replace the extensive inventory of utility infrastructure that has simply worn-out or has become dangerously obsolete. Complying with new government-mandated environmental control measures is also adding to this critical challenge. Among the human-generated events that result in a need for crisis management are extortion, product tampering (such as injecting water supplies with toxic substances), pedestrian deaths caused by utility vehicle mishandling, environmental spills, computer tampering, security breaches, workplace violence, plant explosions or fires, publicly aired allegations of sexual harassment or discrimination, release of hazardous chemicals, and the like. Crisis management is the systematic effort that involves the prompt and effective handling of unusual, unanticipated, and serious problems that all utilities face. Utility crisis planning involves programming the combined tools of analysis, forecasting, and planning in order to be prepared to deal with unexpected crises and disasters. In the past, it has been common for managers to point to a potential crisis having been averted as a measure of the effectiveness of their crisis management programs. Another often-used indicator of success has been stakeholders agreeing that the success outcome of the crisis outweighed any potential failure outcomes (Pearson and Clair 1998). However, in today’s high-risk, high potential-for-crises world, this traditional management approach may not be sufficient. Pearson and Clair recommend the use of this expanded version of crisis management effectiveness measurement in place of the traditional approach: Effective crisis management involves minimizing potential risk before a triggering event. In response to a triggering event, effective crisis management involves improvising and interacting by key stakeholders so that individual and collective sense making, shared meaning, and roles are reconstructed. Following a triggering event, effective crisis management entails individual and organizational readjustment of basic assumptions, as well as behavioral and
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emotional responses aimed at recover and readjustment. (Pearson and Clair 1998, p. 66)
Special Security Concerns The vulnerability of the nation’s utility networks has made security an increasingly important aspect of crisis management. Network security managers find they must now plan on a regional basis and work with a wide variety of public and private stakeholders to develop and manage preparedness strategies. These strategies must include protection, severity reduction, response, recovery, training, and disaster management research and development (Scalingi and Morrison 2003). The Pacific Northwest Partnership for Regional Infrastructure Security (PNPRIS) is an example of a successful cooperative arrangement. One of the training exercises sponsored by PNPRIS involved a disaster scenario devised by representatives from the Bonneville Power Administration; British Columbia Gas; British Columbia Hydro; Boeing; Duke Energy; Pacific Gas and Electric; Williams Gas Pipeline; Puget Sound Energy; the Port of Seattle; the Idaho Bureau of Disaster Services; the U.S. Navy; the National Infrastructure Protection Center; the telecommunications companies Telus, Verizon, and Qwest; the Federal Emergency Management Agency (FEMA); the British Columbia Provisional Emergency Program; and the Canadian Office of Critical Infrastructure Protection and Emergency Preparedness. The scenario theme analysed was a disruption to the Northwest’s electric power grid. It also included terrorist and nonterrorist disruptions of natural gas transmission and distribution systems, municipal water systems, regional ports, and telecommunications systems. Disruptions of those critical public services affected other independent infrastructures, including transportation systems, emergency services, public safety services, hospitals, and cross-border cooperation. A chief result of the training session was that many participants discovered that their organizations’ contingency plans were negated by the cross-border interdependencies that exist among the region’s public services.
SUMMARY The term ‘management’ refers to the set of guiding activities taken by human actors to help others accomplish the many objectives of an organization. Public utility managers apply these activities to accomplish objectives in organizations engaged in providing a public service, including managing all actions relating to the organization’s franchise.
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Management in public utility organizations includes elements of government management, public administration, and management in unregulated businesses. Public management is management under political authority; it is subject to public accountability, shared power, and attention to political influence. Public administration has traditionally been bureaucratic management. The bureaucratic model of government proposed by Max Weber in Germany and Woodrow Wilson in the United States was built upon the following characteristics: centralized and hierarchical control, performance guided by rules and regulations, standardized services, internal staff performing all activities, and objective selection of staff. Two key factors which distinguish the majority of the utility industry from other economic endeavors are: (1) elements of the utility industry operate under socially sanctioned conditions of monopoly competition, and (2) one or more elements of the organizations’ operations or supply chain are regulated by one or more levels of government. Management of public utilities differs from the administrative management that once characterized most government bureaucracies, government regulated utilities, and non-profit organizations. Public utility management today incorporates a mix of traditional dedication to public service tempered by an entrepreneurial, market-oriented managerialism found in the New Public Management. Among the universal management principles are these basic functions performed by all managers: analysing, planning, organizing, directing (leading), and controlling the decisions made to enable the utility to accomplish its objectives. A manager’s freedom to initiate change is limited by certain constraints or limitations. The two broad classes of constraints are external and internal constraints. Five important external constraints are profits, regulatory laws, general laws, public opinion, and social factors. Internal constraints are resource related, although organizational culture may also have a limiting effect upon management’s actions. Recent disasters have made crisis planning and management a major concern of utilities managers. Crisis planning is programming the combined tools of analysis, forecasting, and planning in order to be prepared to deal with unexpected crises and disasters. Crisis management is the system that exists for prompt and effective handling of unusual, unanticipated, and serious problems that all utilities face.
ADDITIONAL READING Barzelay, Michael (2001), The New Public Management, Berkeley: University of California Press.
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Burgelman, Robert A., Modesto A. Maidique and Steven C. Wheelwright (1996), Strategic Management of Technology and Innovation, Chicago: Irwin. Kettl, Donald F. and H. Brinton Milward (1996), The State of Public Management, Baltimore, MD: Johns Hopkins University Press. Starling, Grover (1998), Managing the Public Sector, 5th edn, Fort Worth, TX: Harcourt Brace.
7.
The challenges of utility pricing and rate setting
In market-based economies, prices charged for most goods and services generally are a reflection of supply and demand. When supply exceeds demand, prices fall. When demand exceeds supply, scarcity appears and prices rise. This is referred to as the general model of pricing. The model does not work in exactly this way when pricing the products and services of public utilities. External forces in the form of government regulations and political considerations often intervene in the price-setting process. Furthermore, federally mandated restructuring of the utility industry has introduced a new complexity into the practice of setting prices at all levels of the utility industry. The fundamentals of rate setting, price-setting practices, and such special pricing considerations as social pricing are discussed in the following paragraphs. Throughout the chapter the terms prices and rates are used synonymously, although in the industry, prices are sometimes (but not always) used to describe the wholesale cost of a utility product, with rates used to mean the retail price of the product. Managers in most businesses approach the price-setting process from two interrelated positions. The first begins with the revenue requirements of the organization: income must meet the firm’s needs for each. These include cash for debt service, operating costs, providing an appropriate return to investors, and more. The second begins at the opposite end of the chain: determining what specific combination of prices, rate structures, and rate schedules will bring in the revenue required. This model is more complicated when the organization or business is a public utility (Farris and Sampson 1973). Another set of conditions underlies the rate-setting decisions of utility managers and state and federal regulators, who must now devise new regulatory – including price control – systems that maintain the fundamental goals of deregulation. These goals include lowering the price of energy to consumers, while also ensuring that supply is always sufficient to meet demand, and results in prices that provide an equitable return for investors. Brennan et al. (2002, p. 82) identified the key questions which regulators must consider when determining rates in this new regulatory environment: 109
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Determining the appropriate rate levels. That is, what prices must be charged for services in order to generate the revenue needed to pay for transmission and distribution of the energy? Identifying the appropriate rate adjustments. That is, how and when should rates be adjusted over time to reflect actual or expected changes in the cost and profitability of transmission and distribution? Building the best rate structure. That is, what contribution to the rates paid by final customers should be allocated to such factors as the time and amount of energy transmitted, the distance the power is shipped, what congestion occurs in the transmission systems, the location of generating facilities, and what prices should be paid by different classes of customer (residential, commercial, or industrial)?
Ciolek et al. (2003) have also commented on the changed conditions that now influence utility rate making. Other than the large amounts spent on unregulated generating facilities, much of the utility infrastructure is in serious need of repair or replacement. In addition, government sources estimate that something like $400 billion must be spent over the next 20 years in new construction to keep pace with growing energy demand. While this is taking place, many utilities have experienced significant increases in operating costs. Together, these forces have reduced the rate of return for many utilities to less than 10 percent. Fundamentals of Utility Rate Setting In practice, the process of setting prices in distribution public utilities involves four steps: (1) determining operating costs, (2) distributing costs among different customer classes, (3) considering relevant load and use factors, and (4) designing the pricing structures that reflect the influences of the first three considerations (Farris and Sampson 1973). Determining operating costs Determining costs involves analysis of four categories of operations: customer service, operations, demand, and overheads (general expenses). Costs attributable to the customer service category include meter reading, billing, connecting and disconnecting customers to the system, collecting past-due-date accounts, etc. Today, these services are often provided by a fourth segment of the utility industry, the independent marketing provider. Regardless of who performs these services, they must still be paid for, and are included in the rate base of the utility. Moreover, whether provided in-house or contracted out to independent providers, customer services
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represent a relatively constant cost of operations and can generally be forecast with some accuracy. Costs attributable to operations are more variable than customer service costs. They include personnel wages and the costs of the inputs to the system. System inputs vary by the different costs of the utility’s products and services. For example, wholesale power prices vary by generation method, and by different types and sizes of generating and transmission systems. Other factors affecting price include the type of fuel used for generation, such as coal, gas, nuclear, or renewable fuels, and whether it is purchased on long-term contract or on the spot market for peak loads. The delivered price of natural gas to a utility system varies by the time and type of demand, supply contract, origin (domestic or international), and other factors, such as climate and weather. Water supply and wastewater prices vary far less than energy prices. Rates and prices for these two utility services, therefore, tend to be far more stable and less complicated to set and administer. Other operations cost factors include such items as the maintenance and repair of the operating systems, depreciation allowances, and excise and sales taxes. Demand related costs for rate-making typically constitute the largest portion of the four categories. In the utility business, these are known by several different names, including readiness-to-serve costs, capacity costs, or load costs. They include the total cost of the operating system, including buildings, pipelines, power poles and lines, distribution networks, and repair facilities. Also included in this category are property taxes, depreciation expenses, capital improvements, return on the rate base, and related expenses of bringing and keeping the utility to the position where it is ready to serve any and all demand placed upon the system. The final category of costs is overhead or general expenses. These may be fixed or variable. They include administrative costs, marketing and public relations expenses, supervision costs, costs of purchasing and supply, industrial relations costs, and all other costs which tend to be common or general in nature, and, therefore, difficult to place in any specific function of the utility. Distributing costs among customer classes Once the management costs have been determined, they must be allocated among the various classes of customers served by the utility; costs are proportioned according to the share of the total cost contributed by each class of customer. In practice, each of the four categories of costs – customer, operations, demand, and overheads – are broken down and allocated according to some relevant standard. For example, customer costs are allocated according to the number of customers in the class. Each customer must
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have an account, each customer has a connection and, ultimately, a charge to disconnect, and each customer’s meter must be read. Operations costs, on the other hand, vary with load demand. There are many different formulas for calculating prices for different use volumes, including formulas designed to produce prices that encourage or discourage additional customer use. Demand costs are the most complex in terms of allocation between customer classes. Not only must each class have a rate schedule, each class varies in the service level demanded, the time of day, volume of use, whether peak or off-peak, and other factors. Table 7.1 illustrates some of the different rates found in a typical electric power utility’s rate schedule Typically, prices are lowest for large users, such as factories or commercial centers, and highest for residential customers. However, prices will tend to vary more during any period for industrial and commercial users than they will for residential customers. Overhead expenses are common to the complete operation; they are usually proportionally allocated to all other costs according to some convenient accounting method. Table 7.2 is a comparison of the 2002 residential, commercial, and industrial basic rates for electricity in cents per kilowatt-hour as reported by 12 different utilities in the Western Electric Coordinating Council region. Considering Relevant Load and Use Factors Utility managers and regulators typically look at four factors when establishing rates for their services: peak load, average load, utilization, and a diversity factor. Peak load refers to the maximum capability of the system. It is measured for a particular time period such as a day, a month, or a year, and is usually referred to as peak demand. The utility must construct a system capable of meeting peak demand together with some level of reserve for unexpected demands on the system, to cover some breakdowns in portions of the system or temporary shutdowns for maintenance and to meet anticipated growth in the service area. Average load, or simply the load factor, is defined as the average load or use of a utility’s services for a given time period. It is usually expressed as a percentage of peak demand for the period. Say, for example, that average demand for electric power in a community during August is 80 kilowatts. However, peak demand occurs during the third week of the month. The utility maintains a peak capacity that is 15 percent above average load. To be able to meet peak demand, the utility will have to be physically able to supply 92 megawatts of power (80 mW plus 15 percent of 80 ⫽80 ⫹12 ⫽92 mW) – even if it occurs just once per year.
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Table 7.1
A partial rate schedule for miscellaneous electric services
Billing class Customer code category R1 R3
R1
R1
RD
RE
G1 GE 20
Type of service
Rate per KWh ($)
Daily customer charge ($)
Residential Single 0.516 (Single phase family; 3separate phase meter apts) Temp. Single 0.516 Construcphase tion service No meter
0.46/day 0.74/day
0.46/day
Permit fee: $35 application: $100
Metered single well service Disabled, single family, apartment Exempt, single family, and apartment Single meter Commercial, schools Construction dry shacks No meter
0.46/day
Low income elderly: 0.46/day
Single 0.516 phase
Single meter Commercial
Adjustments and discount rates/day ($) Low income elderly: 0.46/day
Single 0.516 phase
Single 0.516 phase
Exempt
Single 0.565 phase 3-phase
0.68/day
Single 0.565 phase
0.68/day
0.94/day
Guaranteed demand: Billing code 21
Special fees and connection charges
No transformer $25
With transformer $50
Billing period Single 0.034 1.82/day phase 3-phase 0.94/day 3-phase 3-Phase 0.034 1.82/day 3phase
Demand rate: $6.21 Billing period
Demand rate: $6.21
Source: Public Utility District No. 3 of Mason County, Rate Schedule, effective Jan. 2003.
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Table 7.2 Some retail electricity rates in the Western Electric Coordinating Council Region, 2002 Retail rate (cents/kWh) Company San Diego Gas & Electric Co. So. California Edison Co. Pacific Gas & Electric Co. Riverside Public Utilities Dept. El Paso Electric Co. Sierra Pacific Power Co. Black Hills Power Co. Colorado Springs Utilities PacifiCorp Morenci Water & Electric Co. PUD of Cowlitz County PUD of Grant County
State
Residential
Commercial
Industrial
Average
CA
20.59
20.78
16.96
20.20
CA
13.46
15.65
12.78
14.43
CA
13.41
14.80
10.85
13.69
CA
10.83
10.69
7.80
9.68
TX
11.00
10.07
6.03
9.17
NV
10.38
9.46
7.20
8.73
SD
8.24
7.47
4.93
7.01
CO OR
6.85 6.20
5.84 5.41
4.70 3.57
5.66 4.90
AZ
11.03
10.23
4.38
4.47
WA
5.07
6.05
3.48
3.98
WA
4.04
2.88
2.46
2.99
Source: ‘Benchmarks,’ Public Utilities Fortnightly, January 2004, p. 12.
The costs to build and maintain the necessary plant to meet average and peak demand are fixed; they are considered to be sunk costs. Because of deregulation and forced divestiture of assets, sunk costs have become very important to vertically integrated utilities. When developing customers rate structures, regulatory agencies have allowed a long-term recovery of these sunk costs to be included in rate calculations. When utilities must divest themselves of generating plants and/or transmission lines, some regulators have questioned allowing the utilities to continue to include that cost recovery in their rate calculations. The issue is not yet resolved. Examples of sunk costs include the cost to construct dams and nuclear generators, sink wells, build pipelines, dams and reservoirs, and wastewater collection and
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115
treatment systems. Sunk costs continue regardless of use. Therefore, it is to the utility’s advantage to raise its average load factor as high as possible in order to spread these costs among as many customers as it can. In the past, increasing use has been achieved by promotional pricing, special discounts for, say, all electric kitchens, and other marketing efforts. Some vertically integrated utilities suffered from extremely high sunk costs stemming from prior investments in nuclear and/or very large coalfired power generating facilities. Unbundling of vertically integrated utilities into separate generating, transmission, and distribution companies has caused problems in recovering the sunk costs of the integrated concern by the independent parts of the former concern; state regulatory commissions have not always allowed recovery of those sunk costs. The third factor in load service relates to utilization of the system. It is stated as a percentage of the total system capacity represented by the highest anticipated peak load. A utility that is able to meet a peak demand while operating at 88 percent of its total capacity has a reserve capacity of 12 percent. Even if it never reaches the potential maximum demand, the utility must be capable of doing so if called upon. This contingency factor typically ranges in the area of 15 to 20 percent above the utility’s normal forecast utilization factor. The excess capacity is called the utility’s reserve capacity. Both peak demand and contingency supplies are often produced by the utility’s highest cost methods, and are, therefore, priced proportionally higher than average demand. Moreover, to maintain lower rates, large users of the utility’s product sign interruptible or adjustable service contracts, which allow a utility to reduce or stop service during periods of peak demand. Prices for interruptable or adjustable service are often much lower than prices for ‘firm’ or uninterruptable service. The final load factor considered in utility pricing is known as the diversity factor. Diversity refers to the different peak loads expected from the utility’s different customer classes. If the peak demands all occur at the same time, the diversity factor is one. If they occur at different times, the factor has a higher value. The higher the diversity value, the smaller proportion of total system capacity will be needed to serve a given customer class. Demands that occur at different times are called noncoincidental demands. Utilities with higher noncoincidental demands are able to meet the peak loads of all their customers with a smaller overall system than utilities with demands that occur at the same periods. Commission Influence on Utility Rates State or local regulators set or approve utility rates in most states. The approved rates for investor-owned utilities are based upon an analysis of
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Challenges to management
what regulators consider to be the cost of service, as well as a determination of what constitutes a fair return for the utility. Rates established for publicly owned utilities are usually not subject to this type of regulatory oversight but, instead, are subject to local political and social forces that can have an influence as great or even greater than state utility commissions. Moreover, commissioners and other regulatory bodies are regularly called upon to approve changes in utility rates that are brought about by shifts in the utilities’ operating environment, including, but not limited to, changing political, regulatory, and market conditions. These cost shifts are the decisions made by rate regulators to change the distribution of costs for rate of return decisions and rate-change requests. Designing Pricing Structures Setting appropriate rates for all classes of customers is a complex management task that is made more difficult because of government regulations that control the process and often limit the amounts utilities can change. State public utility commissions, operating under their legislative mandate, set the rates that public utilities can charge final customers for their services by approving or refusing to allow proposed rate increases submitted by utilities under their jurisdiction. After establishing what they consider to be the utility’s ‘reasonable’ operating expenses, commissions then determine the rate base by calculating the value of the utility’s assets. This is done in several different ways. One valuation method is to determine the sum of the total capital invested in the property. Another way is by estimating what it would cost to replace the property at current prices. Valuation of the assets of the utility is the most problematic aspect of utility rate making. Table 7.3 is an abbreviated compilation of the results of some utilities’ requests for state utility commission approval of rate-change requests (Cross 2003). The table also displays the utilities’ previously authorized and newly authorized rate of return on equity. Many utilities have either filed for or are planning to file petitions for rate relief with their state utility commissions. Cross concludes that the traditional way of determining rates of return must be changed to include an allowance for the increased level of risk that exists in the utility industry. Once the value of the utility is established, commissions then develop what they consider to be a reasonable return on the fixed assets of the utility. This reasonable return is a percentage amount applied to the value of the utility investment. The result of this calculation is referred to as a ‘fair rate of return.’ The total of the operating expenses and the fair rate of return on the value of the assets are independent functions that together
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Table 7.3
Some 2003 utility rate request outcomes and rates of return
Company Unisource Energy Corp. Pacific Gas & Electric Co. Public Service Company of Colorado Commonwealth Edison Co. Main Public Service Co. Northwest Natural Gas Questar Gas Co. Madison Gas & Electric Co.
Type of service Gas
Increase/ (decrease) requested ($ million)
Increase/ (decrease) granted ($ million)
Previous authorized rate of return (%)
Newly authorized rate of return (%)
21.0
15
10.46
11.00
Electric
135.5
0
11.20
11.20
Electric
74.4
11.00
10.75
10.80
11.72
0.94
10.70
10.25
6.2
10.25
10.20
Electric Electric
1787
(0.2) 1508
1.27
Gas
38.1
Gas
23.017
11.163
11.00
11.20
Gas
8.00
6.80
12.90
12.30
Source: Phillip S. Cross, ‘A Survey of Recent PUC Hearings,’ Public Utilities Fortnightly, November 15, 2003.
make up the rate base. Pricing decisions for different types of service to different classes of customers are then developed as a rate schedule that will generate the revenue necessary to meet operating costs and provide utility investors a fair rate of return on their investments. Most of the problems associated with this process revolve around disagreements between commissions and utility managements over the value of the utility’s assets. Valuation Considerations and Approaches The first application of the valuation of a utility’s assets as a basis for determining the allowable rate of return appeared in a lower court decision in 1896. In San Diego, etc., v. Jasper (74 Fed. 79, 83), the court ruled that it is ‘the actual value of the property at the time the rates are to be fixed that should form the basis upon which to compute just rates.’ Two years later,
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Challenges to management
the principle was accepted by the U.S. Supreme Court in one of the most important cases on utility pricing ever heard: Smyth v. Ames (169 US 486). The ruling majority ruled that the doctrine of fair value as it was then applied was appropriate. The court ruled that a utility rate base must supply a fair return on the value of the property used for the convenience of the public served. An earning power large enough to provide a utility this fair return is the main test of constitutionally reasonable rates (Glaeser 1957). The Smyth v. Ames decision ruled that in determining fair value, ratemaking authorities (public utility commissions) must take into account the following factors: ●
●
●
●
The original cost of construction; that is, the first cost of the original plant plus the cost of extensions and permanent improvements to the physical plant. This is the historical cost of the tangible property. The amount and market value of the utility’s bonds and stock; that is, the aggregate par value of the capital stock actually issued and outstanding, and the market value as determined by the bonds and stock at current exchange prices. These are the capitalized value and the commercial value of the utility. A consideration representing the difference between the current cost of replacement construction and the original construction cost. Rate-making authorities have generally followed an approach that uses the cost of replacement at the time the rates are being set. Smyth v. Ames added to this what is known as a factor of safety for future courts by adding the conclusion that there might be other costs to be considered in estimating the value of a utility’s physical property.
PROCEDURES FOR SETTING PRICES AND PRICE STRUCTURES Utility managers have at least eight different ways to implement rate structures: flat charges, flat rates, fixture rates, step rates, block rates, demand rates, zone rates, and miscellaneous or combination rates. Of these, most residential customers are charged block rates, whereas commercial and industrial customers often are charged demand rates. Flat charge rates are the simplest to understand and apply. Customers pay a single flat charge for a given time period, regardless of how much or how little energy they consume. This was the system used during the early days of the development of the industry, and is still the system used most
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often for water, wastewater, and some local telephone services. The problem with this system is that it tends to encourage customers to use more of the service, often wasting more than they actually use. Flat charges provide no incentives for economizing, and are no longer used in the energy sector of the public utility industry. The flat rate system replaced the flat charge system once affordable metering devices became available. Customers pay the same amount per unit, with the unit charge remaining the same regardless of the amount used. Flat rate systems were very popular during the growth stage of the industry. The method is used by irrigation districts, and remains in use by some domestic water utilities, who charge so much per gallon, with no concern given to the amount used. It is sometimes called a straight line rate. Fixture rates are used with either flat charge or flat rate systems. Fixture rates are based on the number of fixtures in the customer’s premises. The fixtures may be faucets, sinks, water closets, or any other water use appliance. The more fixtures, the higher the charges or rates charged. A version of the method uses a points-system that bases the rate charged for water upon the number of water-saving (low flow) fixtures installed on the premises, the assumption being that the more fixtures that are available, the greater will be the usage. Step rates are used by utilities that need to stimulate usage in order to decrease per unit costs of the service. When this happens, the costs of providing the service is spread across a wider customer base, with everyone supposedly benefiting from the economies. With step rate pricing, charges per unit decrease as usage increases. These rates were very popular during the 1930s and 1940s, when distribution utilities were in their growth phase of operations. Electric utilities promoted usage by offering reduced rates for what they termed ‘all electric homes,’ with electricity used for lighting, heating, and cooking. Step rates are hardly ever found today; they are regressive in that low-income customers use less but are charged the higher per unit price. Moreover, step rates promote wasteful use of the resource. The block rate pricing system has long been the system utilities use for residential customers. Block rate pricing is similar to step rates in that, after a minimum monthly charge, prices are set on a per-unit basis. However, in the block rate system, the first blocks of service are the lowest priced rather than the higher priced. Prices for subsequent blocks are set at higher rates. Because the earliest usage prices are the lowest charged, block rates overcome the regressive nature of step rates. Block rates also encourage conservation by making greater use of the service increasingly expensive. Block rate systems are used by many electricity, gas, and water utilities for residential customers.
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Challenges to management
Demand rates are used by utilities for pricing service for commercial and industrial customers. The maximum service that might be used by the customer establishes the rate. The utility system must be designed to meet that maximum demand, and must be paid for whether the service is used for a week or a year. Building the capacity to meet demand is sometimes referred to as the readiness-to-serve factor. Demand rates often follow the block rate system, with either an added load factor schedule or the demand factor incorporated into the sliding rate structure. Zone rates are similar to the rates shipping companies charge their customers. They are based upon the distance the product must be moved. Zone rates are seldom seen in electricity distribution companies, but have been common in the natural gas pipeline, long distance telephone, telegraph, and public transit utilities. Rates that do not fall into any of the above categories are grouped together into a miscellaneous rates category. Because state utility commissions must approve almost all prices charged by utilities, a variety of miscellaneous rates are often found in published tariffs. These may include prices for such services as on-site repair or installation of appliances or fixtures, connecting and disconnecting customers, special wiring or extension of service for electricity and telephone customers, special equipment, and the like. They also include special deductions for ‘all electric’ or ‘all gas’ systems. Most public utility price schedules are constructed using combinations of two or more of these rate categories. Their rate schedules almost always include rates for different classes of customers. Many also provide rate allowances for elderly, disabled, and special groups of customers, such as those with very low fixed incomes.
INNOVATION IN UTILITY PRICING The following three results that have been predicted to follow widespread adoption of retail competition in the U.S. utility industry: (1) a long-term reduction in retail prices, (2) increases in the range of products and services available to consumers, and (3) improvements in the overall reliability of the delivery system. However, in the limited numbers of states that have initiated retail competition in electric energy, these payoffs have been slow in coming, if at all (Joskow 2003). A vice-president of the utility firm Sempra Energy Corporation stated the following as one possible reason for the failure of the benefits to appear as expected: [These] benefits cannot be achieved without the addition of an essential element of a competitive market: presenting price signals through the use of hourly
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[retail] prices reflecting wholesale price fluctuations in the broader regional commodity markets for electricity. The hourly pricing of electricity at the retail level should induce many customers to reduce on-peak consumption, bringing pressure on suppliers to drop prices. Furthermore, exposing peak prices to customer choice can also spur the development and introduction of smart services and alternative products. (Reed 2003, pp. 30–31)
The technology that would allow real-time metering of utility product use is currently available, at least for large industrial and commercial users of the products. The widespread use of real-time metering systems was made possible by installation of fiber-optic communication systems that occurred during the 1980s and 1990s. In some utilities, contracts have been negotiated with large users of the product that enable the utility to either reduce a customer’s current load, or to send signals to customers about a forthcoming steep increase in peak load prices. The ability to install such demand-control systems for residential customers is as yet not economically feasible, although many utilities have prepared for its expected occurrence by installing fiber-optic systems within their delivery areas. Until it is possible, retail customers are generally unaware of how volatility in wholesale markets can affect utility operations. Retail customers continue to receive monthly bills determined by a weighted average supply price. Price averaging tends to smooth out and hide daily – sometimes hourly – price fluctuations, including extreme prices. Examples of recent ‘hidden’ extreme wholesale prices are shown in Table 7.4. A customer paying energy rates of 4 cents or less per kilowatt hour might be using power for which the utility was forced to pay a price of $6 per kilowatt hour. One of the greatest disadvantages of the current weighted average retail pricing system is that consumers come to look at electricity as an undifferentiated product. This is not the case in the real world, however. The electricity used at 9:30 in the morning is not the same product as electricity purchased at 11:00 at night. Equally, electricity purchased at 3:00 in the afternoon of a mild spring day is not the same as electricity purchased at 3:00 pm on a peak summer day. If customers pay the same price for the product regardless of the time of day or time of year, they are unable to see any difference in the product and, therefore, are unlikely to alter their consumption patterns without substantial incentives. Social Pricing Considerations Public utility managers face social cost considerations that are not found in most other types of businesses: the need to factor in the regulatory requirement to provide reliable, affordable service to all customers, some of whom
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Table 7.4
Challenges to management
Peak wholesale and average retail prices in six U.S. cities
City Boston Los Angeles New York Philadelphia San Francisco Washington, DC
Period
Peak wholesale price ($ per mWh)
Retail energy rate ($ per kWh)
Retail customers’ implicit discount (%)
April 2000 August 2000 August 2000 June 2000 May 2000 June 2000
6000.00 350.00 1671.08 906.84 350.00 297.78
0.0369 0.0536 0.0857 0.0500 0.0544 0.0499
99.4 84.7 94.9 94.5 85.6 83.2
Source: William L. Reed, Rand Corporation working paper, 2003, p. 32.
are simply unable to pay all or part of the cost of the service. These concerns are particularly important among investor-owned electric utilities, where they are often referred to as public purpose programs (Brennan et al. 2002). The programs result in benefits that extend beyond the normal supply of power. They include offering rebates or discounts to customers who install weather stripping and insulation, and energy-efficient (doublepaned) windows and appliances. Other programs provide price breaks for the use of renewable (green) fuels, funding research, and subsidizing low income, disabled, and elderly customers. An example of social pricing consideration can be seen in the public utility district partial rate structure reproduced earlier is this chapter (Table 7.1). The utility does not charge low-income elderly customers the daily charge of $0.46 for home power use that other residential customers must pay. The $0.46 daily charge for water well power is also waived for this customer class (water well power is a rate category label for electricity used to power rural and agricultural water well pumps). The utility rate schedule also includes a discounted rate for disabled persons and a special rate for a category of residential customers who qualify for an exemption of the daily power charge. Another special service not available to the customers of many public utilities is the option to specify the purchase of blocks of energy generated by renewable fuel and/or environmentally friendly facilities. These ‘green power’ options include biomass generation, wind power, and geothermal production. A typical rate for blocks of green power is the $2.00 charge for a 100-kW-hour-block charged by the PUD. All utilities, whether consumerowned or investor-owned, employ similar rate adjustments for one or more groups of customers.
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Consumer Price Protection One of the traditional responsibilities of state utility commissions – and one of the rationales for their establishment in the first place – is the setting and monitoring provisions for consumer protection. Commissions establish consumer protection rules that apply to all investor-owned utilities (IOUs) within their jurisdiction, while local governing boards do so for consumer-owned utilities (COUs). As a result, there tends to be more uniformity among protection policies for IOUs and greater diversity among COUs. Consumer protection rules exist for such services as credit policies, collecting past due amounts, metering, billing and adjustments, and for handling customer complaints.
SOME FACTORS THAT INFLUENCE UTILITY PRICING In both the natural gas and electricity utilities, the production segments of the industries have been almost entirely deregulated; wholesale prices for natural gas and electricity are now established by market forces, rather than through the previous method that involved utilities making rate-change requests, holding public hearings to validate rate-change rationales, and rate-of-return decisions based on valuations approved or contested by public utility commissions. Consumers’ Perceptions of Utility Prices Box 7.1 is abstracted from a research study funded by the Utility Regulatory Commissions’ primary research organization at Ohio State University (NRRI 2004b). The study was conducted to provide commissions with benchmark data for use in their evaluations of regulated utility requests for rate relief. The study design involved a nationwide telephone survey of the attitudes of residential consumers of electric power, natural gas, and other utility services. Deregulation has also been introduced into the transmission segments, although not as completely as for the producer segment. For example, the gas pipeline (transmission) segment is still controlled by the Federal Energy Regulatory Commission (FERC). Pipeline companies are required by law to permit open access to their lines and are forbidden to exercise price discrimination. Their prices are based on the scope of the services they provide and the distances they carry a customer’s gas. Pipeline firms may provide and charge for such ancillary activities as gas collection from production
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Challenges to management
fields, processing and cleaning natural gas, and underground and surface storage. Customers may be independent gas distribution utilities or large commercial or industrial gas users.
BOX 7.1
CONSUMER PERCEPTIONS OF UTILITY PRICES
In August of 2003, the National Regulatory Research Institute published a benchmark survey of more than 18 000 customers’ opinions of the prices they paid for electricity and natural gas. The data were collected between January 9 and February 3, 2003. Not surprisingly, most respondents reported that the price they paid for electric and natural gas services was ‘high.’ Nearly 66 percent said their electricity rates were ‘high’ and 64.5 percent said that their gas prices were ‘high.’ Nearly 36 percent said they felt that all utility prices were ‘fair,’ while just one percent of all respondents said that the price of electricity and natural gas was low. Overall, female respondents were more likely than male respondents to see utility prices as high. On the other hand, younger customers were slightly more likely to consider prices to be ‘low’ or ‘fair’ than were older customers. Other than for respondents claiming East Indian (the US Census Bureau category for persons from the Indian subcontinent and Sri Lanka) or Hispanic ancestry, there were few differences in the way that members of different ethnic groups responded to the survey; 53 percent of Hispanics and 76 percent of East Indians reported they believed the price of natural gas to be ‘fair.’ All other groups reported they believed the prices to be high. The researchers were not surprised that consumers believed that prices were high. Natural gas and electricity have low elasticities. Because these services are considered to be ‘non-optional necessities,’ consumers are seldom willing to lower demand in the face of moderately higher prices for utility service. Source:
NRRI 2004b.
A similar process occurs in the transmission segment of the electricity industry. The FERC has for some time controlled wholesale transmission prices. Prices are based on type of demand, volume, and distance from the generator. Different prices exist for long-term, short-term or spot, peak or off-peak demand load. The FERC has introduced two different types of
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125
independent operating organizations to provide transmission services. The first is the independent service operator; the second is the regional transmission organization. Vertically integrated utilities are required to turn their transmission lines over to independent operators, which are then required to provide universal access and nondiscriminatory prices. Traditionally, state public utilities commissions controlled prices for vertically integrated utilities by adding up all the costs of generating, transmitting, and distributing electricity during peak and off-peak times, then calculating an average cost per kilowatt-hour produced, and approving a price that guaranteed the utility an approved rate of return. Utilities developed schedules of prices for various customer classes for commission approval. Restructuring – unbundling of the utility industry – has changed this system. The FERC and state utility commissions now require separate regulatory structures for transmission and distribution. Transmission operators are subject to interstate commerce regulation and regulatory control of the FERC. Distribution utilities, on the other hand, are considered to be intrastate and, as a result, come under the supervision of state public utility commissions (PUCs).
SUMMARY An entire new set of conditions underlies the rate-setting decisions of utility regulators today. Some of the questions regulators must consider when determining rates in this new regulatory environment include: (1) the appropriate rate levels – how much revenue should be raised by prices charged for services; (2) the appropriate rate adjustments – how and when should rates be adjusted over time to reflect actual or expected changes; (3) the best rate structure – what contribution to the rates paid by customers should be allocated to various services. The process of setting prices in distribution public utilities involves four steps: (1) determining operating costs, (2) distributing costs among different customer classes, (3) considering relevant load and use factors, and (4) designing the pricing structures that reflect the influences of the first three considerations. Determining costs involves analysis of four categories of operations: customer service, operations, demand, and overheads (general expenses). Once the management costs have been determined, they must be allocated among the various classes of customers served by the utility. Each of the four categories of costs – customer, operations, demand, and overheads – are broken down and allocated according to some relevant standard. Utility managers and regulators look at four factors when establishing rates for their services: peak load, average load, utilization, and a diversity
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Challenges to management
factor. Peak load refers to the maximum capability of the system; it is measured for a particular time period such as a day, a month, or a year, and is usually referred to as peak demand. Average load, or simply the load factor, is the average load or use of a utility’s services for a given time period. The third factor in load service relates to utilization of the system. It is stated as a percentage of the total system capacity represented by the highest anticipated peak load. The final load factor considered in utility pricing is known as the diversity factor. Diversity refers to the different peak loads expected from the utility’s different customer classes. Utility managers have at least eight different ways to implement rate structures: flat charges, flat rates, fixture rates, step rates, block rates, demand rates, zone rates, and miscellaneous or combination rates. Of these, most residential customers are charged block rates, whereas commercial and industrial customers are often charged demand rates. State public utility commissions, operating under their legislative mandate, set the rates that public utilities can charge final customers for their services by approving rate proposals submitted by utilities under their jurisdiction. In both the natural gas and electricity utility segments, the production components of the industry have been almost entirely deregulated; wholesale prices for natural gas and electricity are established by market forces. Deregulation has also been introduced into the transmission segments, although not as completely as for the producer segment. Public utility managers face a social cost that is not found in most other types of businesses: they need to factor in the regulatory requirement to provide reliable, affordable service to all customers, some of whom are simply unable to pay all or part of the cost of the service.
ADDITIONAL READING Berrie, Tom W. (1993), Electricity Economics and Planning, London: Peter Peregrinus. Danielsen, Albert L. and David R. Kamerswchen (1983), Current Issues in PublicUtility Economics, Lexington, MA: Lexington Books. Seidenstat, Paul, Michael Nadol and Simon Hakim 2000. America’s Water and Wastewater Industries: Competition and Privatization, Washington, DC: Public Utilities Reports. Stoft, Steven (2002), Power System Economics, Piscataway, NJ: IEEE Press.
8.
The public utility marketing challenge
For most of the history of the public utility industry, marketing was an uncomplicated, straightforward process. Most integrated utility providers were interested in increasing overall demand for their product. Generating facilities were large in order to benefit from economies of scale, often resulting in an oversupply of product. Rates were controlled by legislative agencies; price competition did not exist. Most customers were charged a flat rate for the product or service, regardless of the amount used. Marketing consisted of encouraging existing customers to use more of the product, or of expanding by moving into new market territories. State laws required utilities to serve all customers; growth from normal population and economic growth taking place in the existing service area was generally slow enough for utilities to meet and exceed all requirements for service. The utility business was considered to be a slow, steady, safe, and undramatic business. Assuming that you knew what you were doing and did it reasonably well, profits were ‘guaranteed’ by law in the form of stateapproved ‘fair’ rates of return on investments. In the few spots where integrated utilities still exist, this level of marketing still functions. It is, however, rapidly dying out, and utility marketing now includes activities related to risk management. Beginning in the 1970s, the nature of the utility industry’s marketing environment changed. A series of petroleum-based energy shocks spread throughout the industry. Government reacted by passing laws to conserve and search for more and new sources of energy. The term ‘demarketing’ came into vogue to describe the efforts introduced to control or restrict demand. Many utilities began programs to market conservation ideas and products. Federal legislation was passed requiring utilities to seek or develop alternative sources of supply. Marketing funds were directed toward research and development. At about the same time, environmental protection and conservation laws were passed. These required utilities to design marketing programs to help eliminate air, water, and soil pollution. By the 1980s, portions of the utility industry were partially deregulated, with competition introduced to the wholesale segment of the supply 127
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chain. The industry developed a futures market to enable producers and distributors to manage the risk associated with deregulated wholesale prices. Now, in the early years of the twenty-first century, marketing means many things to different people. For some, the mention of the word brings to mind the practice of advertising and other persuasive communications to influence demand. For others, it means sales or selling – often with the adjective ‘high-pressure’ attached. In parts of the utility business, marketing has come to mean wholesale sales of electricity or natural gas, most often in a futures market. Therefore, some definitions are in order before proceeding with this description of some of the marketing challenges facing utilities. This chapter discusses some of the challenges that have emerged in utility marketing over the last several decades.
THE EVOLVING ROLE OF UTILITY MARKETING Marketing as a business function has changed over the past 50 years. Emphasis has shifted from gaining market share and growing larger in order to reap the benefits of economies of scale, to what is increasingly seen as an emphasis on developing relationships with customers. Developing and maintaining mutually beneficial relationships with customers, not market share, is seen as the key to sustaining profitability. In the utility business, large size was the preferred norm. Scale economies resulted in construction of ever larger physical plant. As plant size increased, more customers or greater volume of use was needed to lower unit costs. Beginning in the 1960s and 1970s, a number of important social and economic phenomena occurred to bring about changes in the way the utility industry markets its products and services. They also brought about a redesign of the organization, structure, and operations of the utility industry. Several energy crises exacerbated the growth problems faced by utilities in the 1960s and 1970s. The public suffered through rapidly increasing energy prices, long lines at gasoline pumps, and shortages of natural gas. The price of producing utility products paralleled increases in the price of fuel. A quadrupling of the price of oil and gas was a painful reminder of growing U.S. dependence upon foreign supplies for energy. These events brought to light the dangers faced by the nation as a result of shortages of supply and reliance upon foreign sources of energy. Another phenomenon taking place throughout the 1960s and 1970s was a great wave of environmental concern that made consumer protection, conservation, and clean-up a national priority. Among other concerns for the environment, the public’s attention was focused on stopping the widespread pollution of the nation’s water supplies. Along with the conserva-
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tion movement came a public demand for protecting natural resources and a widespread disenchantment with the use of nuclear power for generating electricity. By the end of the 1970s, consumer activism had effectively halted all construction of nuclear generators in the United States. In response to public pressure, the idea of ‘demarketing’ – reducing instead of stimulating demand – emerged in the 1970s. With flat- or average-rate pricing and the absence of nonconformance penalties, however, conservation programs had little long-term effect on consumption patterns. Demand Outpaces Supply Capability As a result of the baby boom of the 1940s and 1950s, by the 1970s, growth in demand was outpacing the ability of utilities to meet their service mandates. Power shortages resulted in electricity blackouts and natural gas shortages. High prices resulted from federally regulated wholesale price caps at the wellhead source. Health problems surfaced from impurities in drinking water, and other system failures came to plague utility management. Moreover, air, ground, visual, and water pollution was rampant. The nation’s utilities needed help. Eventually, government and the public in general came to recognize that the utility industry played a critical role in the economic well-being of the nation. Deregulation was proposed as a solution to the industry’s ills. To deal with these and similar problems, the federal government adopted a major public policy initiative designed to achieve energy self-sufficiency. Federal grants were awarded for the development of innovative ways to meet the demand for energy. The introduction of wind and solar power, biomass, cogeneration, and thermal generation methods, production of synthetic natural gas and methods of handling and shipping liquefied natural gas, among others, came from these federal programs. A consequence of these radical changes in the operating environment of public utilities was greater involvement of the marketing function in utility operations. Also increasing the importance of marketing was the international trend toward deregulation, which resulted in the reorganization of many essential public services, including transportation, telecommunications, natural gas, and most recently, electrical energy. Deregulation includes two important economic and political elements: unbundling of the industry and the preemption of state utility regulatory powers by the federal government. Unbundling of the traditional vertically integrated utility business was proposed as a way of lowering prices and increasing the reliability of supply for all participants in the utility industry. It would do this by introducing market competition at the production, transmission, and in some states, the retail distribution levels of
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the utility industry. Competition at all levels of the industry meant that each organization had to learn the techniques of marketing in the management of its value chain, including demand analysis, advertising, public relations, selling, and other marketing techniques. As markets throughout North America, Europe, and parts of Asia matured in the 1980s and the 1990s, the lifetime value of a customer became a central marketing issue in utilities. This concept emphasizes the need to build relationships and to keep customers over time in order to recapture the ‘back loading’ of revenue. The marketing expenditures necessary to acquire a customer and to construct the infrastructure necessary to ensure service are greatest before the customer agrees to purchase. The customer must remain a purchaser for some period for the utility to recover these costs; the term ‘back loading’ is used to describe this phenomenon (Johnson and Seines 2004).
UNDERSTANDING UTILITY DEMAND FACTORS To understand the marketing function in public utilities, it is necessary to examine the nature of demand for utility products or services (Ilic 2001). At the retail level, utilities typically divide their customers into three broad classes: residential, commercial, and industrial. The average of the service demands by all customers in each of three classes of customers over a given period of time is the utility’s average or ‘base service’ load. The utility must be prepared to meet all average load requirements; it must also maintain a reserve for contingencies – that is, for meeting peak demand. Extenuating circumstances often result in a load factor that exceeds both base and peak demand. Utilities have several choices when this happens. They can purchase product (gas or electric power) from other utilities or from private, nonregulated producers, on what is called the spot market. The term spot market refers to wholesale purchases of power made on the open competitive market. The spot market functions much the same as any commodity exchange: spot market purchases are one-time purchases for delivery of a defined amount of power either immediately or on a specific future date or hour. Because of this demand volatility, spot prices vary significantly from one purchase to the next, while long-term contracts provide for stable prices. Spot prices are usually much higher than contract prices for the same amount of power. Therefore, they usually take place in times of very high peak loads when the utility cannot meet the additional peak demand with its normal supply sources, or when existing generating facilities are shut down for maintenance.
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Or, they can curtail delivery. In 2000 and 2001, the State of California was forced to follow the second path when purchasing power on the spot market became too expensive, and producers refused to sell power to distribution firms that were teetering on the brink of insolvency; it instituted a series of ‘rolling blackouts,’ in which power was cut for brief periods of time in different parts of the state (Brennan et al. 2002). Within a utility’s service load, each customer group has a different load pattern and a different elasticity of demand. Elasticity refers to the willingness and/or ability of a customer to shift consumption in response to price signals. Residential customers exhibit relatively low elasticity; raising or lowering the price of a utility product usually has little effect upon consumption. When the wholesale price of energy or water increases, customers do not take fewer morning showers, brew fewer pots of coffee, or wash fewer dishes. Utility costs represent only a small portion of residential customers’ budgets. Equally, lower utility costs do not result in greater consumption. This is the rationale given for the prevalence of flator average-rate billing for residential customers. Commercial and industrial customers, on the other hand, have greater price elasticity. Utility costs make up a far larger proportion of their operating costs than is the case for residential customers. Owners of office buildings, factories, and the like are far more likely to change their utility consumption patterns when faced with significant price increases or decreases. The rates these customers pay may fluctuate with the type of demand provided. For example, the price of nonpeak period supply is typically lower than for a peak-demand period. Therefore, commercial and industrial customers are encouraged to either shift their load use to non-peak periods, or to cut back on their use in peak-demand times. For example, on days when the outside temperature exceeds 85 or 90 degrees, most workers are just as comfortable when air conditioning cools the inside air to between 68 and 74 degrees Fahrenheit. Thus, getting these customers to raise their thermostats to the higher end of the range can greatly reduce the amount of power needed for air conditioning.
UNDERSTANDING UTILITY MARKETS The root of the verb ‘marketing’ is the noun ‘market’. Markets have been defined in a basic marketing text as ‘a group of potential customers with similar needs who are willing to exchange something of value with sellers offering various goods and/or services – that is, ways of satisfying those needs’ (Perreault and McCarthy 1999, p. G-6). Potential customers for utility products and services include households, commercial and industrial
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firms, government agencies, and not-for-profit organizations. Each of the categories of customers is considered a market. Moreover, each market includes smaller groups or segments of a larger market. For example, included in the industrial and government categories are other utilities who purchase utility products for resale to other groups of wholesale and/or retail customers. Customers of a market do not have to all be in the same location; many markets for goods and services are global. Nor do they have to be limited to one or a few suppliers. The energy market, for example, refers to all the possible suppliers and buyers of electricity, coal, natural gas, and petroleum. There are markets for each of these energy components. The market may be national, regional, or local. The duration of the market may be stated for time periods as long as a century, a decade, a year, or even a day or shorter period. A description of a market for a specific utility’s products generally describes demand in a specific area for a specific period of time.
MARKETING BY INDUSTRY PARTICIPANTS Marketing – the exchange of utility products or services for payment – takes place at two levels in the utility supply chain: wholesale and retail. Wholesaling is the sale of the electricity, gas, or water to a down-channel participant, who will then resell the product on to another channel member or to final customers. The goal of wholesale marketing is to facilitate the transactions between segments. Retail marketing, on the other hand, refers to the sale of utility products to customers who actually use the product. In all product segments of the utility industry – electricity, gas, water, and wastewater – both investor-owned and publicly owned utilities employ one or both of these functions. The trend throughout the industrialized nations of the world is toward more privatization in the industry. Marketing in the Wholesale Sector The term ‘market’ also refers to the demand for products at different levels of the supply chain. Wholesale markets are customers who purchase the product in order to resell it to another firm in the supply chain. In the electricity industry, independent generators sell the power they produce to either transmission or distribution firms, or both. In the natural gas industry, production companies sell gas to pipeline companies and/or local distribution utilities. In the water industry, a few large government-owned water agencies sell water at wholesale prices to local and regional distributors. For all utilities, wholesale and retail markets sometimes include
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overlap, for example, a local retail market may also include large industrial or government customers who buy direct from producers or distributors, but at what are close-to-wholesale prices. For example, Tacoma (Washington) Public Utilities sells a mix of utility products at wholesale rates to two local military bases, the U.S. Army’s Ft. Lewis and McCord Air Force Base. At the wholesale level, utility products are sold in three different markets: the unregulated market, the regulated market, and the spot market (Brennan et al. 2002). The unregulated market consists of sales by either generating or distributing companies to large industrial users under both short and long-term contract. The contract prices generally reflect market conditions at the time the contract was negotiated. The price may remain constant throughout the life of the contract or include provisions for adjustments through escalation clauses. If changes are made, they usually do not fluctuate widely. Other producers often compete for these contracts. The regulated market consists of sales to distribution utilities for resale to any type of customers. Electricity and gas utility distribution companies like long-term contracts because they are assured of a stable source of supply at predictable, reasonably stable prices. Producers like long-term contracts because they are assured of a stable source of revenue to service their often very large debt. However, long-term contracts usually only cover a predicted load (demand) level that does not cover all possible demand. Wholesale sales in the unregulated market typically occur as a result of long-term contracts between suppliers and either transmission or distribution organizations. Often, they take the form of take-or-pay contracts. These contracts assure the producer an income stream which can be used for debt service as well as for investor dividends. The unregulated market includes independent generators of electricity and natural gas producers. The ‘green power’ market – that is, wind, solar, geothermal, biomass, and other renewable fuel energy producers – are often included in the unregulated segment. When demand exceeds the normal or average load, regulated utilities face what is called peak load or peak demand, and they must find other sources of supply to comply with their license to serve. Utilities look to the third type of wholesale market: the spot market. The spot market differs from the contract market because the sales/purchases are made essentially at the very moment the product is delivered. Buyers must pay the going price at that moment. Contract purchases are made in advance of delivery of the product. Contract sales are sold (that is, traded) in futures markets. The process of buying and selling future contracts in energy products is similar to futures trading activities in agricultural commodity exchanges.
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Futures exchanges make it possible for organizations in an industry to transfer the risks from price changes to other parties willing to accept those risks. They are willing to accept the risk because they gain the potential of earning large profits from buying and selling futures contracts. A futures contract binds the parties to the sale/purchase of an amount of utility product for delivery at some time in the future. The contract also typically spells out a way for the parties to be relieved of their contract responsibility, such as a seller refusing to deliver a product and giving the buyer his money back with no penalty. Box 8.1 briefly describes how Dominion Resources, Inc., a large, vertically integrated natural gas and electricity utility located in Richmond, Virginia, participates in market trading.
BOX 8.1
TRADING ACTIVITIES OF DOMINION RESOURCES, INC
As part of its strategy to market energy and to manage related risk, Dominion manages a portfolio of commodity-based derivative instruments held for trading purposes. These contracts are sensitive to changes in the prices of energy commodities, primarily natural gas and electricity. Dominion uses established policies and procedures to manage the risks associated with these price fluctuations. Dominion also uses various derivative instruments, such as futures, swaps, and options, to mitigate risk by creating offsetting market positions. In addition, Dominion seeks to use its generation capacity, when not needed to serve customers in its service territory, to satisfy commitments to sell energy. Source:
Dominion Resources, Inc., 2002 Annual Report, p. 54.
In an unregulated market, prices for alternative supplies to meet peak load can be very high. Distribution utilities have several ways to reduce their reliance on the spot market for meeting load spikes. One of these is by installing real-time metering at the facilities of large users. Real-time metering gives users time to decide to accept delivery of the utility product at a much higher price or whether to shut-down or shift usage to off-peak time periods. Experience has shown that when customers are charged real-time prices, peak-demand for the product is reduced. This, in turn, allows the utility to enjoy a reduction in its required generating capacity (Stoft 2002).
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As a way of avoiding peak demand price spikes, a large number of electricity distribution companies have purchased relatively small gas turbine generators that they use only for meeting peak demand, thus enabling them to avoid very high peak-load spot purchases. In one sense, this may be seen as a step backward in the move toward unbundling of the vertically integrated industry. Marketing in the Retail Sector The process of providing electricity, gas, or water to ultimate consumers is termed in the industry ‘retail marketing’ or ‘retail sales.’ It is usually but not always a part of the distribution segment of the industry. Before deregulation and reorganization of the industry, this was the only place where marketing activities were employed. However, unbundling of the industry into separate production-transmission-distribution components has resulted in an entirely new role for the marketing function. As a result of retail competition, marketing today is often a separate function. Competition will not result in the construction of duplicate distribution systems in a market area. Therefore, distribution systems will continue to function as regulated utilities. To meet their required supply requirements, they will also require substantial investments in permanent physical plants. Marketing activities, on the other hand, usually do not require huge investments. This has resulted in the retail sales/billing/ customer service functions of marketing being opened to competition as a nonregulated business. Utility holding companies are permitted to establish and operate nonregulated marketing operations separate from their regulated utility distribution companies. In some locations, marketing services are outsourced to completely independent specialist firms. Classes of Retail Customers There are three main classes of retail customers: households, commercial customers, and industrial customers. Households include single-family homes and apartments, commercial buyers include offices, retail stores, schools, and government facilities. Industrial customers include manufacturing, processing, and construction firms. Farms may be either residential or commercial buyers, or both. Several types of utility wholesalers exist. They can be investor or publicly owned producing organizations, such as electricity generators, natural gas producers, or water storage organizations. They can also be electric power transmission-grid managing organizations, or natural gas pipeline companies, or operators of water aqueducts or pumping facilities.
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Any of these organizations may sell to firms who will then resell the product. The retail organizations that sell utility products to the three classes of customers can be classified into five different types: (1) investor-owned utilities; (2) consumer-owned utilities, including public power districts, utility districts, and state authorities such as the California Water Board; (3) rural cooperatives, including farm-group owned and rural municipalityowned cooperatives; (4) federally owned utilities, such as Tennessee Valley Authority and Bonneville Power; and (5) independent producers and/or transmission (shipping) organizations, such as pipelines and independent power-grid operators, who also serve customers in a particular area, often near the utility’s source of supply.
THE ROLE OF MARKETING MANAGEMENT The process of marketing management consists of three key activities: Developing a plan with specific objectives, implementing the plan, and monitoring progress in achieving planned objectives. Developing the marketing plan and managing implementation of the program are the two chief tasks of marketing management. The planning activity includes setting realistic objectives for all the marketing program activities. The product of planning is the strategic marketing plan, which specifies both short- and long-term objectives. The marketing plan spells out the tasks that are to be carried out in order to accomplish the marketing objectives. As the basis for the marketing planning activity, marketing managers use the data they gathered during the analysis of the utility’s external and external environments for the overall strategic plan. The second major task of marketing management is to direct the implementation of the plan. This involves allocating people, money, and other resources to the tasks where they can do the most good. The third activity is controlling the implementation of the plans. Two of the chief ways that controlling takes place is through effective budget control and ‘Managing for results’ programs, using such tools as balanced score-cards and the like. Marketing managers are also required to plan, implement, and monitor programs designed to encourage customers to modify their patterns of use. This may mean using less electricity, natural gas, or water; changing the time it is used; or even investing in load reduction technologies. Collectively, these activities are referred to as ‘demand-side management’ (DSM), and refer only to demand modifications that take place in response to utilitymanaged programs. DSM activities include the entire range of actions to
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achieve load modification objectives, including strategic conservation, load management, and strategic load-growth management (Energy Information Administration 1997). The American Water Works Association – although warning that marketing should not take the place of serious public participation programs – reported that all utilities can benefit from the judicious use of marketing: Marketing and branding have become the latest buzzwords for water utilities seeking to improve their communication effectiveness. The marketing paradigm has many advantages and can – in many respects – apply just as easily to a water utility as to consumer products. (Katz 2002, p. 32)
Katz went on to suggest that typical goals for a marketing program might include raising public awareness, creating a brand identity, and gaining acceptance through persuasion. Goals for a public participation program, on the other hand, could be sharing decision-making with the public, learning more about community values and priorities, and gaining acceptance through consensus. Customer Relation Management An increasingly important tool used in marketing plan implementation in the age of wholesale and retail competition in the utility industry is customer relationship management (CRM). CRM is both a management activity and a software program that enables management to gather, collect, and make available all relevant information about customers, their needs, and their preferences. The fundamental processes of a CRM system is the merger into one comprehensive database all the customer information from all sources in the company, with access available to all relevant company users (Kennedy 2004). The goal of the CRM program is to make long-term partners out of customers. As firms develop closer relationships with their existing customers, the probability of a customer switching to a competitor decreases. At the same time, competitors’ costs of gaining customers from the current provider increase with higher levels of customer relationships. On the negative side, the costs of converting customers to even closer relationships also increase (Johnson and Seines 2004). A quality CRM program can have a dramatic impact on the bottom line of a utility, according to a study conducted by the management consulting company Accenture Resources. The study found that an average utility with $2 billion in revenue could increase its pretax profits by $250 million to $360 million simply by improving its CRM capabilities. Even greater profit increases were possible for larger utilities (Lester 2002). Michael Kennedy
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(2004) was also enthusiastic about the potential for CRM, but noted that nearly 90 percent of utilities have yet to adopt the tools and methods of CRM. Despite the general trend toward more and more competition within the public utility industry, there have been a number of spectacular failures. The most prominent of these is, of course, the mishandling of reorganizing the power market in California in 2000, and the implosion of Enron, the Texas-based energy trading company. Less dramatic is the retrenchment moves of some companies and political units away from competition. Energy Atlantic, a wholly owned, retail marketing subsidiary of the Maine & Maritime holding company, announced in 2004 that it would no longer compete in the unregulated retail energy market, and that the company was for sale. At its peak, Energy Atlantic served about 3000 residential, commercial, and industrial customers in Maine with a peak load about 750 megawatts (Power Markets Week 2004). In another example of the retrenchment from deregulation and competition, the state of North Carolina announced in 2002 that it had decided to delay any deregulation for the foreseeable future. ElectriCities, which represents 72 electric cities in the state, supported the deregulation delay (Davis 2002). The term electric cities is a marketing phrase utilities used during the early load-building phase of the industry to describe a community in which electric power was used for all domestic uses: heating, cooking, and other energy uses in the home. A similar marketing phrase – all-electric home – was coined to describe new homes in which electricity was the exclusive energy source. Utilities offered communities and individual customers lower overall rates for ‘all electric’ homes. Natural gas utilities used similar marketing tactics to build demand for their services. Today, these marketing tactics are found only rarely.
ACTIVITIES OF MARKETING The marketing function in all segments of the utility industry, including investor-owned and publicly owned operations, involves application of the following four major activities: (1) defining, measuring, and forecasting demand; (2) analysing and interpreting the relevant controllable and uncontrollable environmental forces which positively or negatively influence the short- and long-term financial strength of the utility; (3) planning, designing and implementing persuasive tools to increase, change, or reduce demand; and (4) the designing, implementing, and managing of related activities to help achieve the operational and growth objectives of the organization.
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Forecasting demand is an art as much as it is a science. Utility managers used a number of different forecasting tools when undertaking this process. The most commonly used method is based on historical information; that is, it uses the record of past load as the basis for projecting future demand. An historical percentage rate of growth or decline is calculated and used with past data to project future levels. The process is called ‘time series analysis,’ and can be carried out with simple, readily available spreadsheet software, such as Microsoft® Excel™. This software also permits manipulating the number used for percentage rate of growth to develop optimistic and pessimistic projections. The demand for energy is often described in terms of a load-duration curve that displays the time period in a year that the total load (demand) is at or above some specified ‘typical’ or ‘average’ demand level for that period (Stoft 2002). Because water and wastewater demand growth rates tend to be less volatile than natural gas and electricity, they are typically forecast from historical patterns. Extraordinary events – such as opening or closing of a major water user or the effects of a protracted drought – are superimposed as positive or negative ‘states of nature’ contributions to the calculated historical rate of growth. As such, their effects are often ‘smoothed’ from the time series projection. Environmental analysis for marketing planning is patterned after the same type of situational analysis used for strategic planning. External, non-controllable factors are evaluated for potential threats and opportunities; internal, controllable factors are examined for highlighting the organizational strengths and weaknesses which affect the utility’s ability to accomplish its objectives. Competitive analysis is becoming increasingly important in certain segments of the industry; this process, together with analysis for strengths and weaknesses, helps management identify what are called ‘strategic gaps’ in the market. These are potential areas of business growth in which the organization has the potential for gaining a competitive advantage. Care must be taken, however, that the utility’s management follows strategies that keep the utility competitive in its core business.
ENVIRONMENTAL CHALLENGES FOR UTILITY MARKETERS Over the last decade, a number of conflicting factors beyond the direct control of public utility managers have converged upon the industry. Utilities facing these challenges have turned to human resources programs to help resolve the conflicting forces (Cumming and Chase 1992). In some cases, the forces have sent conflicting messages to utility marketing
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personnel. Within investor-owned utilities, these external pressures and challenges include: ●
●
●
Balancing the need for revenue growth with requirements to encourage conservation by customers; Balancing the need for shareholder returns with the need to maintain inexpensive, reliable service; Managing diversified (regulated and non-regulated) businesses with competitive problems that are different than those facing the core utility business.
Management responses have included programs that improve the organization’s customer focus, reducing operating costs, and maintaining functional and product quality. Human resource’s role in these programs include building two-way goal setting, increased customer feedback, and expanded emphasis on the utility’s mission and senior management vision. Two-way goal setting has been most problematic. For example, in one northeastern U.S. electric utility, marketing representatives were confused over the mixed messages they were receiving from management. Marketing staff were told to secure more customers, while at the same time, push for greater conservation. They did not know whether to continue to push the benefits of all-electric homes to housing developers, or to work with existing customers to find ways to use less power, or even to accept the utility’s new interruptible service. According to Cumming and Chase (1992, p. 24), ‘Goal setting and reward systems needed to be aligned to send a single, strong message to all of the company’s marketing representatives concerning the appropriate balance between sometimes conflicting priorities.’ Marketing Includes Buyers and Sellers Utility marketing involves buying and selling, regardless of whether the utility functions in the regulated or unregulated sector of the industry. A utility marketer must determine the needs of one or more customer groups, and then design a profitable mix of marketing activities that provide the customers the greatest possible satisfaction with what they pay for a product or service. In a competitive situation, the marketer must design a marketing mix that provides an advantage over the offering of other sellers wanting to meet customer demand. When a firm operates in a monopoly, government regulators often substitute price controls for that of the competitive market.
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Every market contains buyers and sellers. Often, more than one level of buyers and sellers are needed to get products or services to market. As the utility industry developed over the past 100 or so years, considerable consolidation and vertical integration took place. In many cases, large investorowned utilities evolved to produce, ship, distribute, and deliver the product to final customers. These individual firms did all the buying, transporting, selling, billing and other related marketing activities. Box 8.2 is an illustration of how the marketing function operates in a natural gas company.
BOX 8.2
MARKETING IN A DIVERSIFIED GAS COMPANY
WGL Holdings, Inc. is a public utility holding company doing business in Washington, DC, Maryland, and Virginia. Its regulated gas distribution company, Washington Gas Light Company, distributes natural gas to roughly 940 000 residential, commercial, and industrial customers. Marketing to the regulated segment includes customer service, meter-reading and billing, and conservation education programs. The firm’s unregulated affiliates sell gas and electricity in competitive markets, and provide heating, ventilating, and air conditioning products and services (HVAC). The company’s retail energy-marketing subsidiary, WGEServices, sells natural gas on an unregulated, competitive basis directly to residential, commercial and industrial customers. Natural gas marketers compete mainly on price, resulting in relative small gross margins. In 2001, WGEServices also began selling electricity in competition with regulated power utilities in its market area. By 2002, the unregulated segment had 155 000 natural gas customers and 66 000 electricity customers. Its two HVAC affiliates, ACI and WGESystems, market installation and related services to commercial and governmental customers. Marketing programs are used to acquire and keep these customers in the unregulated segment. The nonregulated arm of the firm enters into long-term delivery contracts for retail gas and electricity. As a result, it is exposed to market risk from changes in wholesale gas and electricity prices and from demand fluctuations from periods of higher or lower temperatures (weather risk). Source:
WGL Holdings, Inc., 2002 Annual Report.
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Maintaining Quality and reliability Maintaining product quality and reliability is a big part of the responsibility often assigned to marketing units. In the utility industry, a number of organizations play a role in this effort. Foremost of these in the energy field is the North American Electric Reliability Council (NAERC). This organization was established in 1968 after a disastrous blackout on November 9, 1965, cut off power in the Northeastern United States and Ontario, Canada. The mission of the NAERC is to promote the reliability of the electricity supply for all of North America. NAERC is a non-profit organization controlled by nine regional councils: East Central Area Reliability Coordination Agreement, Electric Reliability Council of Texas, Mid-Atlantic Area Council, Mid-America Interconnected Network, Mid-Continent Area Power Pool, Northeast Power Coordinating Council, Southeastern Electric Reliability Council, Southwest Power Pool, Western Systems Coordinating Council; the Alaska Systems Coordinating Council is an affiliate member. The Environmental Protection Administration (EPA) is the agency with greatest control over water quality in the United States. EPA’s authority extends to monitoring and controlling the treatment and discharge of all recycled wastewater into the environment. The EPA establishes standards on particulate matter, bacteria, and various toxic chemicals found in water. The utility must monitor and correct, if necessary, any discrepancies they find in their water supply.
SUMMARY For most of the history of the public utility industry, marketing was an uncomplicated, straightforward process. Marketing objectives were achieved by encouraging existing customers to use more of the product or by expanding service into new market territories. State laws required utilities to serve all customers in their service areas; growth from population and economic growth in the existing service area was generally slow enough for utilities to meet and exceed all requirements for service. The utility business was considered to be a slow, steady, safe, and undramatic business to be in. Assuming that you knew what you were doing and did it reasonably well, profits were ‘guaranteed’ by law in the form of state-approved ‘fair’ rates of return on investments. Beginning in the 1970s, the nature of the utility industry’s marketing environment began to change. A series of petroleum-based energy shocks spread throughout the industry. Government reacted by passing laws to conserve and search for more and new sources of energy. The term ‘demarketing’ came into vogue at this
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time to describe the efforts introduced to control or restrict demand. Many utilities began programs to market conservation ideas and products. Federal legislation was passed requiring utilities to seek or develop alternative sources of supply. By the 1980s, portions of the utility industry were partially deregulated, with competition introduced to the wholesale segment of the supply chain. The industry developed a futures market to enable producers and distributors to manager the risk associated with deregulated wholesale prices. Marketing has changed over the past 50 years. Emphasis has shifted from gaining market share and growing larger to what is increasingly seen as an emphasis on developing relationships with customers. As markets throughout North America, Europe, and parts of Asia matured in the 1980s and the 1990s, the lifetime value of a customer became a central marketing issue in utilities. This concept emphasizes the need to build relationships and to keep customers over time to recapture the ‘back loading’ of revenue. To understand the marketing function in public utilities, it is necessary to examine the nature of demand for utility products or services. At the retail level, utilities divide their customers into three classes: residential, commercial, and industrial. Within a utility’s service load, each group has a different load pattern, and different elasticity of demand. Elasticity refers to the willingness and/or ability of a customer to shift consumption in response to price signals. Residential customers exhibit relatively low elasticity; raising or lowering the price of a product has little effect upon consumption. At the wholesale level, utility products are sold in three different markets: the unregulated market, the regulated market, and the spot market. The process of providing electricity, gas, or water to ultimate consumers is what is known in the industry as retail marketing or retail sales. It is usually but not always a part of the distribution segment of the industry. Before deregulation and reorganization of the industry, this was the only place where marketing activities were employed. However, unbundling of the industry into separate production – transmission – distribution components has resulted in an entirely new role for the marketing function. As a result of retail competition, marketing today is often a separate function. Maintaining product quality and reliability is a big part of the responsibility often assigned to marketing units. In the utility industry, a number of organizations play a role in this effort. Foremost of these in the energy field is the North American Electric Reliability Council. The Environmental Protection Administration has greatest control over water quality in the United States. EPA also monitors and controls the treatment and discharge of all recycled wastewater.
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ADDITIONAL READING Brennan, Timothy J., Karen L. Palmer and Salvador A. Martinez (2002), Alternating Currents: Electricity Markets and Public Policy, Washington, DC: Resources for the Future. MacAvoy, Paul W. (2000), The Natural Gas Market: Sixty Years of Regulation and Deregulation, New Haven, CT: Yale University Press. Perreault, William D. Jr. and E. Jerome McCarthy (1999), Basic Marketing, 13th edn, Boston, MA: Irwin McGraw-Hill. Warkentin, Denise (1996), Energy Marketing Handbook, Tulsa, OK: PennWell Books.
9.
Information challenges for public utility managers
In the public utility industry, information management is a thoroughly modern concept. A senior academic analyst of the utilities industry during the twentieth century, University of Wisconsin Professor of Economics and Commerce Martin G. Glaeser, never mentioned information technology in his 1957 encyclopedic review of the industry, Public Utilities in American Capitalism. Sixteen years later, the concept was still missing from a later overview of the industry by Martin Farris and Roy Sampson (1973). Today, however, hardly any public utility text or business journal is published without a discussion of some aspect of information technology (IT), information technology management (ITM), or simply information management (IM). Since it began to be widely applied in the 1960s and 1970s, information technology has come to be a powerful, indispensable function in the management of utilities, whether they are large or small, publicly or investor-owned, for profit or not-for-profit. Computers and complex telecommunications systems are now a critical component in the strategies of all electrical, natural gas, and water and wastewater systems (Frenzel 1999). IT has taken on a critical and strategic role in numerous organizations; these firms have become so dependent upon IT to support many core activities that the failure of these systems would critically impair operations (Kearns and Lederer 2003).
KEY CONCEPTS IN INFORMATION TECHNOLOGY Before proceeding with this discussion on the management of information in utilities, several key concepts must be defined. These include information systems, information management, information technology management, and computer-based information systems. Information systems are the information technology tools used by organization managers; they include the firm’s computing and communications systems, and involve both hardware and software. Information management refers to the control mechanisms pertaining to business-related information and communications 145
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standards, policies, and procedures within the firm. Information technology management refers to the planning and management of all IT resources, including people, the infrastructure, standards, and operations of the IT system in the utility. Some authors group the various components of the information system under the activity known as computer-based information systems. This term is also used to describe the various business applications in which computers are used (Post and Anderson 1997; Turban et al. 1999; Laudon and Laudon 2001; McLeod and Schell 2001; Burgelman et al. 2004). Whatever name is used, the parts and purposes of information technology are more or less the same. The key point to remember about all information technology is that it is computer based. Computers are used to collect, process, generate, manage, store, and retrieve data, which are the raw material of IT. The product of the IT system is information. Information is what managers and workers need to become more creative and effective than they would be without the technology (Senn 1995). The purpose of information technology is to help people solve problems. These can be management problems, marketing problems, production problems, quality problems, and many, many more. Some of the many different problem-solving applications of IT in utilities include accounting information systems, supervisory control and data acquisition systems, geographic information systems, energy management systems, customer information systems, maintenance management systems, marketing management systems, laboratory information systems, various production models (such as water quality models and power generation models), and distribution and transmission network models, among others. Some Benefits of Information Technology Many different claims have been made about the benefits that accrue from the use of information technology. Turban et al. (1999, p. 5), for example, described IT as the ‘major facilitator of business activities in the world today,’ and a ‘catalyst of fundamental changes in the structure, operations, and management of organizations.’ The importance of information systems has also been described in the following way: Managers cannot ignore information systems because they play such a critical role in contemporary organizations. . . . The entire cash flow of most . . . companies is linked to information systems. Today’s systems directly affect how managers decide, how senior managers plan, and in many cases what products and services are produced (and how). They play a strategic role in the life of the firm. (Laudon and Laudon 2001, p. 15)
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In their survey across 11 industry categories (including utilities), Kearns and Lederer (2003) found that a majority of the firms responding used IT as an integral component in their strategic approach for gaining competitive advantage. The next section describes some of the ways IT is applied in public utilities.
INFORMATION TECHNOLOGY APPLICATIONS The introduction of IT in utility management that took place over the last several decades has produced performance gains that may be traced to the introduction of four applications models (Heller et al. 2001): (1) information system technology (IST), (2) utility communications architecture (UCA), (3) utility business architecture (UBA), and (4) what has been described as business ecology (BE). In the broadest sense, information system technology refers to the application of computers and software to provide essential information to managers and anyone else needing the information. Utility communications architecture is that part of the system that allows full exchange of data within and outside the utility; the UCA links sections and units, administration, customers, vendors, and other utilities electronically, using Internet, extranet, and intranet architecture. Utility business architecture, on the other hand, refers to the methods and tools used to model operations in terms of the utility’s organization, processes, and resources. And finally, industrial (or business) ecology refers to the integration of operational, environmental, and economic systems; the BE process involves a drive toward alternative production and consumption of utility products and services to minimize waste and control the use of natural resources. These concepts are discussed in greater detail in the following pages. Components of Information System Technology Writing about management applications in public organizations, including public utilities, Grover Starling (1998, pp. 563–4) identified the five chief components of all information systems: (1) inputs, (2) processing, (3) storage, (4) control, and (5) output. Inputs are the raw data collected for the system. For utilities, these data may include information about demographics, financial data, tax rates, and the rate and period of product use for various classes of customers. Other data of concern include stream flows, snow pack quantity, power production capacities, interest rates,
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wages, benefits, and a host of other production, operations, and management data. Processing refers to the ability of the system and its operators to manipulate, organize, sort, and perform statistical processes on the data. Processing has two key objectives. The first is to convert raw data into information that can be used by managers. The second is to organize data and information into meaningful collections of relevant tools for decision making. Processed data are not always needed when processing is completed. The data must be held for the time that they are needed. This action takes place in the data storage function of the information system. Proper data storage and database maintenance are important to all of the five functions. Data must be retrievable and up-to-date to be of value. Closely associated with the storage function is the control of information system data. Control systems exist to ensure that the information delivered meets time, quality, completeness, and relevance requirements of system users. Output is the last of the five chief components of all information systems. Output refers to the many different types of reports and other information produced by the information system. A problem in the past was that the information supplied by the system was often what the information system managers felt that users should have, not what the users needed or asked for. Output was often entirely unsuited for the task of improving decision making. Today, however, this problem has been largely resolved. Now, information management planning begins with identifying user needs. Once needs are established, teams work together to develop the reports that provide the needed information in a timely and efficient manner. Box 9.1 contains a list of principles that public and private-sector utilities should consider in developing their communication architecture. Web-Based Utility Communications Architecture The many components of information technology, including the Internet, are at the heart of the new way of carrying out the activities of public and private organizations. In the public sector, this new way of operating is referred to as ‘e-government.’ In the private sector, it is called ‘electronic commerce,’ or simply ‘e-commerce.’ Both e-government and e-commerce employ telecommunications as a key part of the organization’s value creation and value delivery processes (Riggins and Rhee 1998). The public utility sector of the economy – which includes both publicly and investor-owned electricity, gas, water and wastewater utilities – involves both e-government and e-commerce.
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INTEGRATING COMMUNICATIONS SYSTEMS ARCHITECTURE
An integrated utility information management model includes a network of systems and subsystems, many of which have different hardware. Utilities information systems and subsystems must be able to supply information communication with each other in order to support intersystem applications. Integrated systems under a common database structure allow units to share data. To achieve integration, a utility must adopt the following interrelated system development principles: ●
● ●
●
●
Multiple function integration – as many functions as reasonable should be built into the same system; Modular design – design hardware as discrete modules; Distributed intelligence – locate information storage, processing, retrieval, and decision making as close to the operation as possible; Expandability – incorporates extra capacity into the system, its components, and interconnections; Open architecture – standardize component interfaces, software specifications, and protocols.
Source:
Heller et al. 2001, p. 282.
E-government is defined by Hughes (2003, p. 182) as ‘the use of information technology, in particular the Internet, to deliver public services in a much more convenient, customer-oriented, cost-effective, and altogether different and better way.’ Hughes includes a broader definition in which he describes e-government as the adoption of any information and communication technology by government. The information technologies included in this definition include video conferencing, touch-tone phone entry, CD-ROMs, the Internet and private intranets. New technologies such as interactive television and mobile telephone and personal digital notebook access to the Internet may also be included. One observer has reported that information technology and e-government are now critical components in all other sectors of government (Kamarck 2004). E-commerce is defined by Riggins and Rhee (1998, p. 89) as ‘the sharing of business information, maintaining business relationships, and conducting business transactions by means of telecommunications networks.’
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In addition, e-commerce represents more than just buying and selling electronically; it includes using network communications technology to conduct a variety of business activities up and down the value chain, both in and out of the organization. E-commerce applications include customer-to-business, businessto-customer, business-to-business, and inter-organizational communications. The inter-organizational application is particularly important in utilities with geographically dispersed operations, using the Internet, by extranet, or in intranets. The Internet, of course, is a global communications medium. One of its primary uses by utilities is for communicating with customers. Extranets are business-to-business applications. They are used by utilities as cooperative networks that use Internet technology to link with suppliers, customers, and other organizations in their supply chain. Riggins and Rhee also identify a fourth network they call a ‘supranet,’ which is a semi-open, consortium sponsored network of firms in a supply chain. Examples of firms in a natural gas supply chain include wellhead producers of natural gas, pipeline companies, storage firms, distribution organizations, and possibly one or more large gas users, such as an industrial firm. Similar connections of organizations exist in the electric power industry. Water and wastewater supply chains are similar, but are usually less complex. In addition to the primary organizations in the chain, a number of service and equipment suppliers might also belong to the consortium network. The modern, integrated information systems that are now being implemented in public utilities incorporate knowledge management systems with supply chain management systems, customer information and relationship management systems. Examples of how utilities are employing these new technologies are discussed in the following sections. Utility Business Architecture Among the many types of system applications that became available from the 1960s on, four basic computerized information systems formed the early systems employed in public utilities: management information systems, transaction processing systems, decision support systems, and early expert systems. Utilities employed independent applications programs and applications servers to perform specific functions, such as billing, calculating payroll, etc. (An applications server is a computer that only runs specific application programs.) The following statement points out the perils of sticking with systems that have been developed independently:
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Information systems designed and implemented in isolation only serve the needs of other utility divisions by coincidence. The ability to share data must be designed into systems . . . Otherwise, a utility will not be able to use existing data to the extent necessary to be truly competitive or will be forced to duplicate the data, often by manual reentry, in numerous internal systems. The result is increased costs, data discrepancies, unwieldy database management, and confusion. (Heller et al. 2001, pp. 280–1)
Although each component in the system was designed to perform specific functions, a great deal of overlap was seen in the information needs of managers. Therefore, it became apparent that the systems needed to be coordinated and meshed somehow. Coordinating systems would result in avoiding duplication while also making needed information available when, where, and to whom it is needed. Today, information technology management ties all these individual systems together. Information systems are built around telecommunication systems that make use of the Internet, extranets, and intranet technology. The process of tying together all systems in the organization and to the Internet is called enterprise application integration (Schneider 2003). Public Utility Business Ecology For years, the heart of all information technology in utilities was the management information system (MIS); this application is discussed here as an application of business ecology. The MIS was the first attempt at integrating production and consumption data to improve the management of the complete value-generating and delivery system. MIS-based systems are still used by many small utilities who have not yet upgraded to modern, integrated systems. The following is a definition of the MIS: A management information system (MIS) is a computer-based system that makes information available to users with similar needs. The users typically comprise a formal organizational entity – the firm or a subsidiary subunit. The information describes the firm or one of its major systems in terms of what has happened in the past, what is happening now, and what is likely to happen in the future. The information is made available in the form of periodic reports, special reports, and outputs of mathematical simulations. The information output is used by both managers and nonmanagers as they make decisions to solve the firm’s problems. (McLeod and Schell 2001, pp. 239–40)
Today, these older MIS-based systems are often referred to as legacy systems because of the way they developed piece by piece over the years
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and were passed down to later management with little or no modification. Newer IT applications added to the firm usually had to mesh with the basic management system. Other applications were supported and added to it. Moreover, these newer applications had to reflect the basic values and beliefs of utility management (Frenzel 1999). Some of the chief components that evolved to augment the basic MIS include transaction processing systems, decision support systems, and expert systems. The fundamental purpose of the MIS is to collect, organize, and distribute the data that managers and other personnel need to perform their particular tasks in the organization. Managers use MIS-produced data to follow the status of their programs, projects, personnel, revenues, expenses, and similar activities. Transaction processing systems (TPS) were among the first applications of computers in utility operations. The TPS systems that emerged during the 1960s were introduced to reduce clerical costs and time by standardizing and computerizing day-to-day transactions. Examples included meter reading interpretations and utility billing and payment. Today, TPS systems still perform the routine, recurring transactions of many small utilities, although modern comprehensive systems have absorbed many of their functions. Decision Support Systems Decision support systems (DSS) are another product of computerized information systems. DSS systems were developed to aid public service managers solve both unstructured and semistructured problems that most early TPS and MIS systems were unable to handle (Starling 1998). DSS systems enable the utility to collect and recover, process, and make available the information a manager needs to make a specific decision. Capital project planning and management are typical applications of DSS systems. The term artificial intelligence (AI) is used to describe a variety of computer applications designed to mimic human behavior. This includes learning from experience, understanding written and spoken language, and making inferences from evidence. Expert systems are a version of AI. These systems use the collected knowledge of human experts to enable the computer to infer that situations with similar characteristics are likely to have similar conclusions. Example applications relevant to utility operations include zoning law problems, construction regulations, rate-making procedures, and similar regulatory issues.
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Examples of IT in Public Utilities Today, many utilities are upgrading their IT systems. For example, the combined electricity–water–rail utility of Tacoma, Washington, began major improvements to its IT systems in 2002 with contracts for a total enterprise system with SAP, the German software company, and TUI Consulting, a global consulting firm. The goals of the Tacoma Utility Business System Improvement Project are to improve customer service, enhance work efficiency, and give managers more and better tools for evaluation and analysis (Tacoma Utilities 2002). The utility is redesigning work flows and implementing new customer billing, financial management, and work management systems. When the project is completed, the utility’s four major computer systems – customer information, financial management, work management, and human resources – will be integrated. They will share a single database, thus improving service to customers and employees. The customer information system is an example of IT adopted by utilities of all types and sizes. Maine Public Service Co. is a small rural power provider with business in Northern Maine and New Brunswick, Canada. Until 1947, the firm was a wholly owned subsidiary of Consolidated Electric & Gas Company. In 1999, the regulated, fully integrated utility chose to reorganize as a holding company, and filed for a name change to Maine & Maritimes Corporation (MAM). In addition to the original Maine Public Service Co., MAM’s operating-company subsidiaries include Energy Atlantic and Maine & New Brunswick Electric Power Co. All three subsidiaries continue to function as regulated utilities. Increased investment in information technology is an important part of the company’s reorganization plan. Box 9.2 is a report on the company’s IT investment. The recent IT program planning and design experiences of several additional public utilities are described in Box 9.3. The information officers at the three investor-owned utilities were interviewed for a picture on the information needs and plans of utilities over the next several years beginning in 2003. The shift from legacy systems to fully integrated, web-based IT systems in these utilities is not without its problems, however. For example, not everyone agrees on the advisability of placing all of the organization’s data into one integrated repository with open access for all users. Some of the dangers associated with this development are highlighted in Box 9.4. The discussion also includes a number of safeguards which are recommended for use by database system designers.
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BOX 9.2
INVESTMENT IN INFORMATION TECHNOLOGY IN A SMALL INVESTOROWNED UTILITY
With its change in management and governance, MPS made an increased commitment to information technologies, which included a major policy change. The new policy is based on the belief that computer literacy must be a mandate for all employees, regardless of the position they hold in the company. Therefore, every employee is provided access to computer education. The goal of the program is to increase the computer application skills of all employees. A first step in the new emphasis on information technologies was to employ a nationally recognized consulting firm to conduct a comprehensive audit of the computer use and information needs of the firm. That benchmarking study resulted in a plan to upgrade all information technologies in the firm, including an evaluation of the use of mobile computing for line crews. Additional steps included an increased emphasis on the use of the geographic information system, and evaluation of a new finance system to facilitate a planned move to activity-based accounting. Source:
Maine Public Service Company, 2002 Annual Report.
BOX 9.3
UTILITY CHIEF INFORMATION OFFICERS DISCUSS PLANS AND PROBLEMS
In June of 2002, the editors of Utility Business asked the chief information officers(CIOs) of three U.S. utilities about their insights on the information needs of their firms, their IT spending plans, and internal IT issues they then faced. Interviewed were Jim Kenesok of Avista Corp., Spokane, Washington; Willard Evans of People’s Energy in Chicago, Illinois; and Bryan Kearney of the Idaho Power Co., Boise, Idaho.Jim Kenesok described Avista’s objectives for information technology: ‘Improve earnings, customer management, community relations and employee focus through integrated business, financial, and operations applications and data;
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accommodate existing legacy systems while introducing strategic applications.’ Willard Evans, CIO of People’s Energy, described his firm’s IT experiences: ‘Recently, we’ve reorganized human resources, IT, and other support services to form a shared services organization. . . . Our challenge is to shift the paradigm of our customers from thinking of IT as a cost center, or in some cases a free service, to leveraging IT as a strategic business enabler.’ When asked what the ‘digital utility concept’ meant to him, Evans replied: ‘The digital utility extends beyond the e-biz hype. The digital utility employs technology to all aspects of its business processes. For example, it involves the digitalization of facilities, commodity loads and acquisitions, automated metering, and service notifications and dispatching, automatic e-billing and e-payment, smart appliance and smart house integration and customer service self-provisioning. The digital utility provides a seamless automated integration of products and services to customer.’ Idaho Power provides electric power in Idaho, Oregon, and Nevada. The firm generates most of its own power in 17 hydroelectric and three coal-fired plants. Bryan Kearney, the firm’s CIO, described his information technology objectives: ‘[To] leverage technology to improve customer service, operational efficiencies, reliability and safety, physical and cyber security.’ He identified several of his chief challenges as: ‘Managing the convergence of new and sometimes competing technologies, managing the increasing physical hardware inventory effectively, [and] staying current on all software fixes and patches.’ Source:
Anonymous, Utility Business, June 2002, pp. 55–9.
BOX 9.4
DATA WAREHOUSE PROBLEMS AND SAFEGUARDS
Data warehousing is a hot topic. However, it has the potential to ‘burn a company,’ according to Public Utilities Fortnightly editor Jennifer Alvey. A recent survey found that 41 percent of all data warehousing programs fail. Data warehousing is the consolidation of all company data and information into a single database, regardless of the application
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that generated the data. Information technology managers know that not all parts of the integrated system will fit well together; as a result, they often turn to outside consultants for assistance in developing the system. The following six safeguards are recommended for any utility planning to develop a data warehouse project: ●
●
●
● ●
●
●
Make absolutely sure you are extracting, transforming, and loading the data right the first time; this is critical if the warehouse is to work; Have a clear idea of the utility problems to be solved with use of a data warehouse; Do not add more and more features to the project as development moves along; Plan any additions before beginning; Take special care to avoid ‘scope creep’ – expanding the scope almost guarantees missing implementation deadlines; Gain end-user participation and acceptance during all phases of the project, but particularly during the planning and development periods; Plan to spend more money to maintain the warehouse once it is up and operating.
Source:
Jennifer Alvey, 2003, Public Utilities Fortnightly, (October 1), p. 25.
The merchant power generating firm Cinergy represents another example of how utility firms are expanding their investment in IT. According to Bennett Gaines, Cinergy chief technology officer, the firm is making major investments in IT applications, including its customer management, billing, and financial systems. The firm is also consolidating its various databases into one combined set called a ‘data warehouse,’ with common terminologies and an indexing system with the same meaning for everyone. It is focusing on linking financial and operational data so that they can be used in different operational environments. The ultimate goal for the integrated system is for everyone in the corporation to have access to the data they need to do their job (Wipro 2004). The Utility CIS and CRM The Customer Information System (CIS) has become an important contributor to improvements in public utility effectiveness and profitability. Its
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two chief benefits are that it can help the utility build revenues, while at the same time promote greater customer loyalty (Burkhart 2004). Much of the MIS is now part of the modern information system. Customer information systems are a major component in the new integrated information technology systems that are replacing old legacy systems in utilities. The CIS is a spoke in the wheel of technology-enabled relationship management; it is a part of the broader concept called ‘customer relationship management,’ or CRM (Lester 2002; Schneider 2003; Kennedy 2004; Seines 2004). Other terms used to describe the same activity include technology-enabled customer relationship management and electronic customer relationship management (eCRM). Every utility has a distinct group of customers; CRM uses the Internet to gather detailed information about those customers, including preferences, needs, and buying patterns. These data are then used to set prices, shift demand to off-peak periods, negotiate terms, tailor promotions, add features and services, and other customer-related actions (Schneider 2003). Developing a comprehensive customer database that includes needsatisfaction information about each class of customers is the initial step in what is called ‘customer portfolio management.’ The principal process of a customer relationship program is merging the once-isolated parts of customer relationship information into a single comprehensive database (Kennedy 2004). No information can be considered to be ‘owned’ by any unit or person in the utility. Rather, all vital information must be available through the firm’s intranet to everyone who needs it. Moreover, it is also important that the system not remain static; it must change to reflect changes in the operating environment of the utility. As an example of the dynamic nature of the CIS, the IT consulting firm Wipro Technologies was called on to redesign a CIS system they had developed earlier for a utility in the Pacific Northwest. The primary users of the customer information system in the utility are customer call centers, business centers, engineering and operations departments, field crews, and management at all levels of the utility. For reasons beyond the control of the utility, the old system was found to be failing to meet the needs of these users. The system needed to be brought up to date. The needed changes to the CIS were brought on by passage of state legislation introducing choice and competition in the market area of the power utility. That legislation required (1) unbundling of services the company provided to its customers, (2) increased customer choice, and (3) introduction of competition in the non-residential energy services market. These changes then resulted in widespread revisions to the regulatory environment of the utility. Changes were needed in each of the following seven functions of the integrated CIS:
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1. 2. 3. 4. 5. 6. 7.
Challenges to management
Electricity service supplier management Retail customer management Franchise license taxes Product offerings management Retail customer settlement payments and collections Retail customer billing, and Electricity service supplier billing.
IT in Publicly Owned Utilities Publicly owned utilities are also making major investments in information technology infrastructure. Recent legislation gave wholesale telecommunications authority to public utility districts. This has resulted in public utilities making large investments in fiber-optic communications systems. For example, the Chelan County Public Utility District is developing an openaccess, public fiber-optic network for delivery of broadband communications services to its private and public customers. Mason County PUD No. 3 has developed a fiber-optic telecommunications system between its ten distribution substations and has installed a Supervisory Control and Data Acquisition (SCADA) system for control of operations. The next step in their program is to connect business and industrial customers to the network. The network-expansion experience of Chelan County PUD, a combined electricity, water, and wastewater integrated utility, illustrates how utilities are taking advantage of this new business opportunity. The PUD spent more than $12.5 million in 2001 and 2002 to install a 60-mile-plus system of fiber-optic cable and related equipment to its dams, substations, and headquarters. The objective of the network was to improve the control and communications systems of the utility. Over the past several years, the utility has expanded the network into outlying communities in order to link all school districts, hospitals, and community facilities in the country. Businesses and private citizens will also be given access to the network. The Tacoma, Washington, municipal utility has developed an even more ambitious goal for its fiber-optic network. In its primary mission, the network is considered to be the central tool for automated controls throughout the utility electrical distribution system. The system has enabled the utility to reduce the length, frequency, and scope of power outages. Tacoma Power has also tested a project that combines available meters, cable modems, computers and software with fiber-optic telecommunications. The goal of this project is to enable more accurate and timely reading of specialized industrial meters for eventual real-time metering of power use in peak-load conditions. What may possibly be the most far-reaching application of IT in the Tacoma utility has been the development of an integrated fiber-optic cable network that
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serves customers in the city and two neighboring communities. The system, named Click!, includes cable television, business telecommunications, and Internet access. Special metering connected to the Click! network will soon give customers the ability to read their energy-use patterns, thus controlling heating, cooling, and air conditioning use. Moreover, Tacoma Power will be able to conduct such normal utility operations as connecting and disconnecting service, and detecting meter tampering, electronically. A Multi-Product System Example Ghahramani (2003) described the development and installation of an integrated IT system designed for a multi-product, vertically integrated metropolitan utility. The system was constructed to replace an old system of diverse, independent applications and batch information system that was no longer able to meet operational needs. The old legacy system was not only inflexible, it was also difficult to maintain and use. The legacy system employed sequential batch processing using tapes. Daily updating of the Information System Master File was carried out from different locations including order entry, cash, meter reading, bill calculation, revenue, rate system, audit system, and other subsystems. The legacy system could not produce on-demand reports needed by management. The event that triggered replacement of the antiquated legacy system was construction of a new nuclear generating plant. The utility had to raise rates to pay for the new nuclear plant. This, together with increases in demand, made the new system necessary. Management wanted to offset higher rates by providing better customer service. The old IBM mainframebased system and of additional systems added over time was replaced with a Lean Management Information System (LMIS) that could meet current and expected future growth. The new LMIS uses a mid-range central server with magnetic disk carousel storage, an Oracle database system, and a user-friendly interface. On-line processing has replaced batch processing. Users have access to information on user-friendly screens and can submit reports and other results via the Internet. The LMIS also meets current IT requirements, including: (1) a new method of storing information; (2) a new system for collecting customer information; (3) a new system for handling service orders; an effective process to create statistical reports on customer service orders; and (5) user-friendly entry panels. The LMIS has three chief components: 1. 2. 3.
Customer application maintenance system (CAMS) Service order entry system (SOES) Reporting system (RS).
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The CAMS is used primarily by marketing and energy service representatives to gather customer information. It is used to collect, analyse, monitor, and store information based on new customer accounts, account delinquency, account changes and closures. SOES is used by the customer account analysts to enter and schedule work requests and ask about current accounts, work request history, and new entries. The RS produces standardized reports such as the number of service orders issued daily, and all service work not completed within 30 days. Managers are also able to produce customized reports, selecting the RS tables they want and add other information. The Customer Information Database (CID) is also part of the LMIS. CID data are stored on the magnetic disk carousel, which allows random access to the data by any utility user. The database includes such information as customer name, account number, work request history, payment history, and meter reading history.
SUMMARY Since it began to be widely applied in the 1960s and 1970s, information technology has come to be a powerful, indispensable function in the management of large and small, publicly or investor-owned, for profit and not-for-profit, public utilities. Computers and telecommunications technologies are now a critical component in the strategies of all electrical, natural gas, and water and wastewater systems. The introduction of IT in utility management has produced performance gains that may be traced to the introduction of four applications models: information technology, utility communications architecture, utility business architecture, and what has been described as industrial or business ecology. ‘Information technology’ is the descriptive term used to describe the management and application of information in organizations. IT incorporates the utility computing and communications systems and includes both hardware and software. ‘Information management’ refers to the control mechanisms pertaining to business-related information and communications standards, policies, and procedures within the firm. ‘Information technology management’ is used to cover the planning and management of all IT resources, including people, the infrastructure, standards, and operations of the IT system in the utility. Information technology is computer based. Computers are used to collect, process, generate, manage, store, and retrieve data. The product of the IT system is information that can be used by managers and employees. Information is what managers and workers need to become more creative
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and effective than they would be without the technology. The purpose of information technology is to help people solve management, marketing, production, quality, and other problems in organizations. The five chief components of all information systems are: (1) inputs; (2) processing; (3) storage; (4) control; and (5) output. Inputs are the raw data collected for the system. Processing refers to the ability of the system and its operators to manipulate, organize, sort, and perform statistical processes on the data. The data are held in the data storage part of the information system. Control systems exist to ensure that the information delivered meets time, quality, completeness, and relevance requirements of system users. Output refers to the many different types of reports and other information produced by the information system. Four basic types of computerized systems comprise the information found in many small public utilities: management information systems, transaction processing systems, decision support systems, and expert systems (artificial intelligence). The core of these systems was the management information system. Other applications must support and add to the management system. The many components of information technology, including the Internet, are at the heart of the new way of carrying out the activities of public and private organizations. In the public sector, this new way of operating is referred to as e-government. In the private sector, it is called electronic commerce or simply e-commerce. Both e-government and e-commerce employ telecommunications as a key part of the organization’s value creation and value delivery processes. The public utility sector of the economy – which includes both publicly and investor-owned electricity, gas, water and wastewater utilities – involves both e-government and e-commerce. The modern, integrated information systems that are now being implemented in public utilities incorporate knowledge management systems with supply chain management systems, customer information and relationship management systems. The customer information system and customer relationship management have become important contributors to improvements in public utility effectiveness and profitability. The two chief benefits of this approach are (1) it can help the utility build revenues, and (2) at the same time promote greater customer loyalty. Publicly owned utilities are also making major investments in the installation of information technology infrastructure. Recent legislation gave wholesale telecommunications authority to public utility districts. These utilities are providing fiber-optic telecommunications service and Internet access to businesses and community agencies in their areas.
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ADDITIONAL READING Frenzel, Carroll W. (1999), Management of Information Technology, Cambridge, MA: Course Technology (ITP). Laudon, Kenneth C. and Jane P. Laudon (2001), Essentials of Management Information Systems: Organization and Technology in the Networked Enterprise, 4th edn, Upper Saddle River, NJ: Prentice Hall. McLeod, Raymond Jr. and George Schell (2001), Management Information Systems, 8th edn, Upper Saddle River, NJ: Prentice Hall. Schneider, Gary P. (2003), Electronic Commerce, 4th edn, Boston, MA: Course Technology.
10.
Utility finance and accounting challenges
The drive for deregulation and restructuring of the public utility industry has brought substantial modifications to its regulatory structure. This, in turn, has resulted in a host of new challenges being added to the traditional problems of financial managers. Public utility finance officers must now focus on more than the old questions of return on investment and recovery of investments in the industry; they are becoming more involved in justifying the investment and operating decisions that must be made to meet the needs of a newly designed, unbundled, industry that is characterized by financial turmoil. Public utilities have always been heavily dependent upon outside investment. There are few if any industries that are so consistently in need of large infusions of capital. The costs for the following infrastructure improvements must be paid for in the next several decades: ●
● ● ●
● ● ●
Designing and constructing huge coal-fired or nuclear generating systems; Constructing dams and reservoirs; Exploring and drilling for natural gas; Constructing an entire new infrastructure to receive, store, and distribute liquefied natural gas (LNG); Laying new natural gas pipelines; Upgrading the North American electricity transmission grid; And more.
Payment for these new facilities will be spread over very long periods of time – in some cases, as long as 50 years or more. Repaying the huge loans that will be needed for these utility infrastructure improvements will require public utility commissions to allow utilities to subtract the debt service from operating revenues. Otherwise, reasonable rates of return will not be maintained, and investors will not provide the needed capital. Today, one of the greatest challenges facing public utility managers is the problem of capital acquisition. Until recently, economies of scale, 163
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Challenges to management
together with mandated reserve capacity, meant that very large utility plants represented the most economical way to add capacity. Very large plants require very large amounts of outside capital. Vertically integrated, regulated utilities were seen as sound, stable, long-term investments. There is evidence that this state of affairs will return, as the large number of small natural gas generating plants that have been built over the last ten years has resulted in a severe shortage of natural gas. Shortages, in turn, have resulted in unprecedented increases in gas prices. Some industry observers conclude that small gas generators are no longer economically viable (Bezdek and Wendling 2004).
FINANCE AND ACCOUNTING MANAGEMENT CHALLENGES Collectively, these challenges are here grouped under the broad management category of finance and accounting. Finance deals with the processes associated with raising capital; accounting is the keeping of accounts and producing reports about the use of that capital. Public utility managers have at least three major objectives in mind when they plan for financial management: how to increase the resources available for operations, how to maintain stable growth at rates high enough to attract equity capital, and how to maintain autonomy and control over resources and operations. In utilities, the finance function requires decision-making in at least four principal areas: (1) capital structure, which refers to the ratio of debt to equity in the financing of the organization; (2) the operating expense and investment structure, which are influenced by the regulatory environment; together, these heavily influence the utility’s allowed return on investment; (3) the acquisition and cost of capital, which are shaped by the financial strength of the utility; and (4) working capital requirements, as determined by the liquidity picture, which itself is influenced by the capital structure of the utility. Utility accounting decisions and the production of financial reports are reflections of decision-making in these five management areas: (1) maintaining an historical record of all transactions, (2) designing and maintaining systems of internal controls, (3) establishing the financial basis for the regulation of rates and earnings, (4) federal, state, and local taxation, and (5) in investor-owned utilities, producing data that are used for gaining and maintaining investor confidence.
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The Capital Structure of Utilities Like all enterprises, public utilities need money to pay their bills, and they often need more money to improve and grow the enterprise. Both public and investor-owned organizations borrow money to make more money (this use of borrowed money is called leverage). Debt can be either short- or long-term. Both investor-owned and publicly owned utilities turn to long-term debt with bond sales to finance expansion and system upgrades. Often, the city’s credit rating is mirrored by the credit rating of the utility. While equity in investor-owned utilities comes from individual investors and institutions that purchase the stock as an investment, publicly owned utilities are financed almost exclusively through debt. Eventually, retained revenues from operations may provide the organization its needed working capital, so the publicly owned utility may rely less on short-term borrowing than is the case with investor-owned utilities. Organizations secure capital to finance their operations with debt or equity, or both. The proportions of debt and equity make up the capital structure of the organization. Organizations need money to start operations, and then they need more money to continue them. Equity is the money an entrepreneur or investor puts up to get the enterprise going. The money received from sales of stock is called stockholder’s equity. But equity is usually not enough to enable the enterprise to grow at the desired pace. Additional financial resources may be acquired in a number of different ways, including but not limited to the following: ● ●
●
●
Through loans from banks or other financial institutions; By borrowing from investors (either outright or in the form of the sale of bonds); By providing additional ownership to investors by selling them more stock in the company; Or by using retained earnings or revenue.
Most utilities employ a mix of long-term borrowing in the form of bonds with a relatively small proportion of bank loans in the form of a line of credit for working capital. Frank Napolitano, managing director of the Global Power Group at the Lehman Brothers Investment Bank, has described the relationship between three different types of financial structures with their associated level of risk as seen by investors. The structure with the lowest perceived risk is the traditional vertically integrated utility (VIU). The financial structure of the VIU is approximately 50 percent recourse corporate debt
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Challenges to management
(recourse debt refers to borrowed funds for which lenders retain an option to convert the debt to common stock), 45 percent equity, and about 5 percent in preferred stock. While investor-owned utilities as a whole tend to have a high proportion of debt financing, the traditional vertically integrated utility was seen by investors as having a low level of risk because of its regulatory commission-approved ‘fair’ level of return of investment (Napolitano 2004). The next structure, still with a low level of perceived risk, is a nonregulated power generator with a long-term purchase contract in hand, as established under PURPA regulations. These power generating operations were financed with anywhere from 80 to 90 percent non-recourse corporate debt (debt the cannot be converted to common stock), and with a corresponding 10 to 20 percent equity. They are called ‘contract power projects.’ The capital mix structure with the highest level of risk is the merchant power-producing project, whose capital mix consisted of from 60 to 80 percent non-recourse project financing debt, and corresponding 40 to 20 percent equity. Many of these small generating organizations failed as a result of the 2000–01 power crisis that began as a result of mistakes made in California’s reorganization of its power industry. As a result, a number of lenders found themselves owning electric power generators. Utility finance managers are still facing challenges from those problems, as the following statement indicates: The bank markets and the long-term fixed income markets, or institutional investors, have long memories, and their pain is still fresh. Over the last few years, they have had to watch their investments in power infrastructure become distressed, bankrupted, or reorganized. . . . the undeniable fact is that investors will remember what happened in the United States, and they remember privatizations in foreign countries where they experienced similar losses. In short, investors are wary. (Napolitano 2004, p. 53)
THE FINANCE FUNCTION IN PUBLIC UTILITIES The public utility industry has undergone several years of financial crisis upon crisis. The first two years of the new century have been marked by what one observer has called ‘stomach-wrenching ratings downgrades, agonizing downward valuations, embarrassing accounting scandals, skyrocketing gas prices, and positive stubborn mild weather’ (Stavros 2003 pp. 31–8). Two of the chief concerns of utility financial managers today are looking into the future to find answers to the questions: Will investors regain their interest in utility equities? And, will enough investment capital
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167
be available for the massive investments needed in upgrading and adding capacity to the nation’s utilities? Utility managers look to financial management to help guide them through this sea of problems. Financial management in utilities consists of two major activities: (1) planning for and acquiring financial resources and (2) planning, monitoring, analysing, and reporting how those resources are used to accomplish the organization’s objectives. Among the many tasks financial managers employ in these processes are budgeting, forecasting, accounting and financial reporting, financing, auditing and related financial analysis, and development and operating financial information systems (AWWA 1995). Financial management has two overarching goals: ensuring that cash flow remains positive, and ensuring that there is sufficient cash available when needed to enable the utility to grow as demand requires. Achievement of these goals is made possible by following this five-step process (Rachman et al. 1993, p. 543): 1. 2. 3.
4.
5.
Estimate month-by-month flow of income (revenue) into the utility from all sources; Estimate the month-by-month flow of money out of the utility, including operating expenses and capital investments; Compare income with expenses. If more cash is needed, determine the best way to acquire it. This can include reducing expenses or increasing revenues. If excess cash is generated, determine the best place to invest excess funds; Select the capital investments that must be made for continued growth; find the most cost-effective combination of inside and outside financing sources; Forge a system for tracking the flow of funds and monitoring the return on investment.
To summarize, the finance challenges facing utility managers are (1) planning for and acquiring financial resources, using either debt or equity or both, as appropriate, and (2) planning, monitoring, analysing, and reporting the use of those funds. In carrying out their responsibilities, financial managers use such tools as accounting and reporting, budgeting and forecasting, auditing and analysis, financial information systems, and custodial and resource management. This task includes facilities maintenance, personnel, inventory control, and financial services. The accounting function serves as the foundation for all financial activities that follow.
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THE ACCOUNTING FUNCTION IN PUBLIC UTILITIES The accounting function records transactions, processes operating data, prepares financial reporting information, and collects and distributes management information. Record-keeping begins with the accumulation of information. Financial and statistical data flow into the accounting function both from within the firm and from other operations. All the transactions that take place in a utility – buying, selling, depreciating, trading, storing, etc. – must be recorded. This includes recording the movement of materials, people, and supplies from one location to another (Farris and Sampson 1973; Bozeman and Straussman 1991). In the US, what data must be recorded, reported, and retained by investor-owned utilities is largely controlled by rules and regulations enforced by the Securities and Exchange Commission and/or the Internal Revenue Service. Publicly owned utilities must follow accounting regulations established by a variety of federal and/or state regulatory agencies. Similar regulatory processes control recording and reporting procedures elsewhere. Accounting provides at least four major services in utilities: (1) it maintains an historical record of the financial transactions of the firm, (2) it makes operating information available to other people in the firm for budgeting, forecasting, and performance monitoring, (3) it provides a basis for establishing a system for controls within the organization, and (4) it provides analysis of results and produces reports on the financial health and vigor of the utility to investors and owners who depend on the information for making investment decisions. The following text focuses on the record-keeping function of utility accounting. Maintaining the Historical Record Two major accounting systems are used by all sectors of the public utility industry: One, the NARUC system, is used by investor-owned utilities. The second is the Governmental Accounting Standards Board (GASB) system, which is required for all government-owned utility organizations. The GASB is an independent, non-profit organization that sets and monitors financial accounting and reporting standards for state and local governments. Purposes of the GASB include the following: (1) ensure that appropriate and complete information is made available for users of financial data (such as government bond rating agencies, consulting preparers and auditors of financial reports), (2) guide and educate the public on government financial activities, and (3) improve financial accounting and reporting standards used by state and local governments (GSAB 2004).
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169
Although there are more similarities in the systems than differences, each will be discussed in greater detail in the following pages. Before financial transactions can be meaningfully recorded and reported, a utility’s assets, liabilities, equities, revenues, and expenses must be classified using a comprehensive system of accounts. This can then serve as a basis for a logical and pertinent summary for management. Uniform systems of accounts are also used to allow for proper consolidation of accounts in utilities with more than a single operating company. Most investor-owned utilities use a system of accounts recommended by their industry organization, the National Association of Regulatory Utility Commissioners (NARUC). The need for accounting information by state utility commissions in their regulatory operations and by other interested parties is so great that the design of accounting systems used by regulated utilities is usually based on commission requirements. Privately owned and operated utilities rely on profitability as the incentive for investment. As a result, investors generally require significantly more information than may be needed in publicly owned utilities. In addition, regulatory agencies and other groups require detailed records of the revenues and expenses of utilities. The Securities and Exchange Commission (SEC) also requires a uniform set of accounts for ease of comparison, among other reasons. The minimum requirements for the system of accounts used by investorowned utilities are usually established by each individual state utility regulatory agency. In practice, however, most commission-required systems follow the NARUC system and are very nearly identical. Key Components of the NARUC System The NARUC system of accounts includes five chief components and several supportive components (AWWA 1995). Together, these components provide information necessary for developing and maintaining a complete record of the financial activities of the utility. The five chief components are: ● ● ● ●
●
General instructions and definitions; Instructions for identifying utility plant and operating expenses; A specified list of accounts into which records are maintained; A definition of each account and instructions concerning the types of transactions to be recorded in each account; A sequence for balance sheet and income statement items.
The first two components provide instructions that guide the utility’s accountants through the system of accounts. General instructions are
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Challenges to management
statements of instructions relating to approved accounting standards; new statements are issued periodically to reflect system changes and new regulations. These instructions spell out the form and content of the system of accounts that the utility’s accountants must follow. Because state utility commissions must approve all expenses for inclusion in the rate base, identifying, recording, and justifying operating expenses are extremely important activities. Allowed expenses are used for developing the approved rate base and calculating the utility’s rate of return. The next three components define and delineate the number and types of accounts that must be maintained. Each of the chief summary accounts may be backed by additional supportive accounts. Two sets of primary accounts are included in the system: (1) balance sheet accounts, and (2) income accounts. A third set of accounts, the retained earnings accounts, is used as a means of connecting the information in the two primary accounts. Each of these primary accounts contains two or more subsidiary accounts. For example, the two chief balance sheet accounts are (1) the assets accounts, and (2) the liabilities accounts. These two balance sheet accounts are further divided into 11 groups of summary accounts. In addition, many of the summary accounts are themselves supported by additional subsidiary accounts. The primary balance sheet accounts and 11 major summary accounts are displayed in Figure 10.1. Each account is assigned a numeric code for identification and consolidation; only major code categories are shown in the figure. As noted, many of the individual summary balance sheet accounts are supported by subsidiary accounts or records. These provide additional details about specific components of the summary accounts. One such summary balance sheet account – Utility plant – is supported by six functional groups of detailed subsidiary utility plant accounts under the NARUC system. Plant in service is the largest asset on the balance sheet of utilities. Because of this large investment, state and municipal regulations have established certain financing and cost-recovery mechanisms in some states. Identified as ‘capital-recovery fees,’ ‘impact fees,’ and ‘land development fees,’ they may require special accounting considerations. Special uses may impact on rate calculations under different cost-of-service, ratemaking methods. This detailed structure is necessary because of the importance of plant and facilities information to regulatory commissions for determining the appropriate rate base and to appropriately record depreciation. Detailed utility plant information also facilitates effective management control of plant assets. The subcategories in an example water utility plant account include the following sections: intangible plant, source-of-supply plant, pumping plant, water treatment plant, transmission and distribution plant,
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171
Balance sheet accounts (100-299)
Assets and other debits (100-199) 1. Utility plant 2. Other property and investments 3. Current and accrued assets 4. Deferred debits
Figure 10.1
Liabilities and other credits (200-299) 5. Equity capital 6. Long-term debt 7. Current and accrued liabilities 8. Deferred credits 9. Operating reserves 10. Contributions 11. Accumulated/deferred income
Balance sheet accounts in the NARUC system
and general plant. Similar subsections are found in electric and gas utility balance sheets. Income Accounts The second set of primary balance sheet accounts is the set of income accounts. The income account is built around four major components: (1) utility operating income, (2) other income and deductions, (3) interest charges, and (4) extraordinary items. Utility operating income is computed by subtracting operating expenses from operating revenues. Only operating expenses which occur from delivering the utility’s product are allowed; revenues are the income derived from normal operations of the utility. From the point of view of public service regulatory commissions, operating income is often referred to as being above or below the line. Regulated utilities are entitled to operating revenues sufficient to cover operating expenses and provide for a ‘fair’ rate of return. Return is the money that remains after operating expenses have been subtracted from operating revenues. Some of this money is used to pass dividends to investors, while some is retained and used to pay for future operating expenses, improvements, or repairs. Revenues and expenses that commissions accept in the
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determination of operating income are said to be above-the-line items. Expenses are above-the-line items if they are accepted as being reasonable in amount and are considered chargeable against customers for utility services provided. Below-the-line items are not considered as operating items in calculations of rates and the determination of a fair or reasonable return. However, they are included as adjustments to operating income in arriving at the net income of the utility. Moreover, income from non-utility activities and non-utility income deductions and related income taxes are considered to be belowthe-line. Interest charges are not classified as operating expenses and thus are below-the-line; they are considered in the allowable rate of return. Other Income and Deductions The second major category of information in the income account is other income and deductions. This account includes income that does not come from the normal business of supplying the utility product. Examples include charges for installations, revenue from appliance sales or leases, interest and dividend income, etc. The other income deductions account includes miscellaneous amortization charges which are not included in the utility operating income and miscellaneous deductions. Examples include charitable donations, efforts to influence public opinion, elections or appointments of officials, and losses on write-downs or sales of securities, allowable taxes, and related items. Interest Charges Interest charges are the third component in the income accounts under the NARUC system. This account includes interest on both long-term and short-tem debt; the amortization of debt discount, debt premium, and debt-issue expense; interest on debt to associated companies; and all other interest expenses. Extraordinary Items Extraordinary items include any unexpected gains or losses which might distort the income of the current year if they were reported as operating revenues or expenses. An example of an extraordinary gain might be proceeds from the sale of a property parcel. An example of loss in this category might be the extraordinary costs (earnest money) associated with failure to consummate the purchase of another segment of the industry, a property parcel, or similar asset.
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Financing and accounting
An Example Utility Consolidated Balance Sheet Table 10.1 displays a five-year consolidated comparative balance sheet produced by a typical natural gas utility (the categories are real, but the Table 10.1
Example comparative balance sheets for a natural gas utility Comparative Consolidated Balance Sheet
Long-Term Assets: Utility Plant Less accumulated depreciation Utility plant – net Non utility property Less accumulated depreciation and depletion Total plant and property Other long-term investments Total Long-term Assets Current Assets: Cash and equivalents Accounts receivable Accrued unbilled revenue Inventories, materials, supplies Prepayments and other assets Total current assets Regulatory tax assets Deferred gas costs receivable Unrealized loss on non-trading derivatives Deferred debits Total Assets:
2003 ($000)
2002 ($000)
2001 ($000)
2000 ($000)
1999 ($000)
1 945 694
1 729 722
1 584 425
1 493 321
1 303 669
(627 983) 1 317 711 17 221
(568 395) 1 161 327 14 222
(545 200) 1 039 225 9 455
(478 675) (443 555) 1 014 646 860 114 8 320 7 016
(3 879)
(3 687)
(3 872)
(3 453)
(3 250)
1 331 053
1 171 862
1 044 808
1 019 513
863 880
19 584 1 350 637
27 450 1 199 312
15 756 1 060 564
14 500 1 034 013
17 822 881 702
11 212 51 369
10 455 61 258
12 586 60 457
8 479 51 227
9 275 40 789
45 875
59 878
54 921
48 119
41 272
61 321
52 473
47 852
46 245
41 095
27 465 197 242
29 527 213 591
21 545 197 361
17 982 172 052
16 532 148 963
49 523
48 588
47 300
47 895
49 525
15 745
19 256
25 421
83 694
75 982
76 337
68 215
64 215
1 681 096
1 537 473
1 397 307
1 341 431
1 169 826
174
Table 10.1
Challenges to management
(continued ) Comparative Consolidated Balance Sheet
Capitalization and liabilities: Capitalization: Common stock equity Redeemable preferred stock Total Capital stock Long-term debt First mortgage debt Unsecured debt Total long-term debt Total capitalization Current liabilities: Notes payable Accounts payable Long-term debt, due one-year Taxes accured Interest accrued Other current and accrued liabilities Total current liabilities Other: Deferred investment tax credits Deferred income taxes Fair value, non-trading derivities Deferred gas costs payable Regulatory liabilities and other Total other: Total capitalization and liabilities:
2003 ($000)
2002 ($000)
2001 ($000)
2000 ($000)
1999 ($000)
633 850
594 118
691 124
511 690
479 785
7 850 641 700
7 679 601 797
6 936 698 060
6 520 518 210
6 129 485 914
593 750 5 655 599 405 1 241 105
522 500 6 503 529 003 1 130 800
459 800 7 479 467 279 1 165 339
404 624 18 605 423 229 941 439
359 069 21 396 380 465 866 379
82 158 63 899
75 996 59 107
70 296 54 674
65 024 50 573
60 147 46 780
35 000 8 295 3 120
32 375 7 673 2 886
29 947 7 097 2 670
27 701 6 565 2 469
25 632 6 073 2 284
28 474 220 946
26 338 204 375
24 363 189 047
22 536 174 868
20 846 161 762
8 542 157 695
7 517 65 641
8 419 15 737
7 409 205 150
8 372 121 550
97 825 11 278
10 425
41 530 219 045
22 890 204 298
18 765 42 921
12 565 225 124
11 763 141 685
1 681 096
1 539 473
1 397 307
1 341 431
1 169 826
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Financing and accounting
Table 10.2
Example of a retained earnings account
Year ended December 31 Earnings invested in the business: Balance at beginning of year Net income Cash dividends paid: Preferred and preference stock Common stock Common stock repurchase Common stock expense Balance at end of year
2003 ($000)
2002 ($000)
2001 ($000)
147 950 43 792
134 189 50 187
118 711 50 224
(2 579) (32 024)
(2 410) (31 307)
(2 466) (31 198)
– (3) 157 136
(2 688) (21) 147 950
(1 080) (2) 134 189
values have been modified from the original). In this example, the consolidated balance sheet includes data for the utility’s regulated and nonregulated, wholly owned subsidiary businesses. This utility serves an area that extends across several states and is subject to regulation by several state commissions. The firm’s revenues come from the sale and transportation of natural gas; revenue is recognized when the gas is delivered to and received by the customer. The comparative balance sheet contains an interesting item not found in most other types of businesses: a reserve fund to be used if commission rate proceedings require refunds to utility customers in future periods. The regulatory tax assets were listed as $49.8 million in 2003 and $48.6 million in 2002. Retained Earnings Account The purpose of the retained earnings account is to explain changes in a utility’s retained earnings balance over a particular time period. In some cases, the category has been included in a scheduled labeled ‘Statement of earnings invested in the business.’ This group of accounts is used to explain changes in a utility’s retained earnings balance over some time period, such as one year. Table 10.2 is an example of such an account for a natural gas utility. These changes may be caused by changes in net income, distribution of retained earnings during the time period, dividend declarations or transfers to other municipal funds, or other accounting adjustments.
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ACCOUNTING IN PUBLICLY OWNED UTILITIES The NARUC system applies only to investor-owned operations; it must be modified if it is used by municipally owned utilities. Government-owned organizations, including municipally owned utilities, are required to follow a specific uniform system of accounts known as the GASB system. The GASB system is based on recommendations of the National Council on Government Accounting. The government accounting system shares many of the same features as the NARUC system, but because municipal utilities are not required to earn a profit, some differences in the accounting systems exist. Differences exist in regulations on financing and cost-recovery for the physical plant, centralized support services, and accounting costs for services provided by other utilities in the same municipality. For example, water and wastewater services are often combined into one municipal utility. Costs for billing and other services must be appropriately distributed. A municipal utility operated as a self-sustaining operation must generate revenues that are sufficient to cover all expenses, which may include taxes or payments in lieu of taxes and depreciation. It must additionally generate revenues for expansions of the system if it is required to finance expansions. Challenges arise when the municipal utility is operated to result in a break-even or a loss (subsidized) financial basis. The utility must find a way to generate enough revenue to cover future costs. In most municipalities, a city-owned utility that operates as a separate accounting entity has important and continuing relationships with other funds for such centralized services as purchasing and transportation. For example, the utility may ‘rent’ office space and common maintenance facilities from the city or county. Or, it may pay into a common retirement fund and be charged a proportionate share of fund overheads and participate in other centralized services. Centralized services are usually accounted for through a working-capital fund, with payment taking place by fund transfers. There may be other important transfers between the utility and other funds of the municipality. Examples include: (1) the transfer of a portion of the utility’s retained earnings to the general fund, (2) the transfer of resources from the general fund to the utility for financing purposes, or (3) pay into special revenue funds in lieu of property taxes or a return on investment. The system of accounts must be designed to record interfund transactions between municipal funds. Municipally owned utilities should be accounted for as a separate enterprise fund, not on a fund accounting basis, as are most other government operations (AWWA 1995).
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Recent Modifications in the GASB System Recently, a critical set of challenges facing government-owned utility operations has been identified. Publicly owned utility finance managers have had to learn how to implement the extensive series of changes required in the GASB system. This new system of accounts is required for government bodies, including states, cities, towns, villages, and public utilities. The new system is expected to restructure much of the information that governments must provide, with the goal of making annual reports more comprehensive and easier to understand and use. The changes are included in the ‘Statements of governmental accounting standards No. 34’ (AICPA 1999). Government organizations produce annual reports in the same way that investor-owned enterprises do. These reports provide information about funds established by governing bodies. Such information is used to show the planned use of resources, as well as how the agency will monitor shortterm revenues and expenditures arising from their activities. Moreover, an important part of accountability is showing that the government organization is in compliance with its budget. Government agencies, including utilities, must continue to provide budgetary comparison information in their annual reports. However, with the new standards, they must submit the original budget to the comparison, rather than a budget that has been revised one or more times during the period in question. Another important change is the required increased involvement of government financial managers in the annual report. For the first time, government financial managers must share their insights in a required management discussion and analysis (MD&A) section in the annual report. In the MD&A, financial managers must give readers an objective and understandable analysis of the government’s (i.e., the utility) performance for the year. The analysis is to give users information needed to help them assess whether the organization’s financial position has improved or deteriorated as a result of the year’s operations (anonymous 1999). Table 10.3 is an example of a combined income statement for a regional public utility district in the Pacific Northwest; while the schedule contains all of the information categories, it does not follow the preferred system to the letter. Utilities were given a sliding time scale to follow in conforming to the new standards. Organizations and governments with total annual revenues of $100 million or more were required to apply Statement 34 by June 14, 2001; those with revenues from $10 million to less than $100 million were to implement the statement by June 15, 2002; and those with revenues of less than $10 million were given until June 15, 2003, for implementation.
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Table 10.3 Example of a combined income statement for a publicly owned utility 2000 ($)
1999 ($)
Total operating revenues
62 381 445
57 343 636
Operating expenses Maintenance expenses Depreciation expenses Taxes Total operating expenses
24 975 435 5 585 085 6 170 201 2 259 303 38 990 024
24 259 960 6 199 837 5 932 336 2 493 404 38 885 537
Net operating revenues Interest and other income Gain on early retirement of long-term debt Non-operating margin – other Balance available for debt service
23 391 421 4 508 809 298 080 46 827 28 245 137
18 458 099 3 113 251 170 834 147 954 21 890 138
Interest on long-term debt Other debt expense Total interest and other expenses Excess of revenues over cost of services Net addition to retained earnings
9 645 426 990 159 10 635 585 17 609 552 17 609 552
9 244 091 978 381 10 222 472 11 667 666 11 667 666
141 543 487 159 153 487
129 876 269 141 543 935
Retained earnings, January 1 Retained earnings, December 31
Annual reports for publicly owned utilities contain most if not all of the same financial information found in the annual reports of investor-owned utilities. The two chief summary statements are still the balance sheet and the income statement. Balance sheets must also show assets and liabilities; income statements contain much the same four components found in investor-owned utilities: (1) utility operating income (which includes operating revenue and operating expenses), (2) other income and deductions, (3) interest charges, and (4) extraordinary items, if any. Making Accounting Information Available Information for management and operating use is an important goal of the accounting function. Metered water sales are an example of operating information. Another form of operating information is budget variance reports. Figure 10.2 illustrates the relationship between the sources of accounting information and the types of reports that use accounting data. In this system, raw data comes from internal and external sources. Internal data include such information as production cost figures. An external data
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Financing and accounting Operating data: Non-operating data: • • • •
Labor Materials Equipment Overheads
• Financing activities • Investing activities
ACCOUNTING INFORMATION
Financial reports
Source:
Management reports
Operations reports
AWWA: Water Utility Accounting, 1995.
Figure 10.2
The flow of accounting information
example might be withholding tax or interest rates, inflation rates, and similar uncontrollable factors. Controls in the NARUC System The NARUC system of accounts emphasizes the grouping of cost data on a functional basis, such as source of supply, treatment, transmission, distribution, and marketing services. For planning and control purposes, management is interested in cost information based on a natural classification, such as labor, fuel, and rent. Therefore, within each functional group, costs are identified according to their natural classification. Effective cost control requires that definite responsibility for costs be established. A manager should be held responsible for only those costs that he or she can control. Therefore, the system of accounts must allow for identification and presentation of costs incurred by each responsibility segment (organization unit) of the utility organization. Cost data and related operating statistics enable utility managers to set performance standards and to prepare realistic operating budgets. Comparison of actual costs and operating statistics with planned costs and performance standards grouped by unit responsibility makes it possible for the financial manager to take action to control cost and improve performance.
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In addition to transaction data, procedures such as reconciliations of customer deposits, accounts receivable, and bank statements provide important internal controls for utilities. Policies and procedures are the basic guidelines and instructions to the utility and staff for the processing of these transactions. Standard operating procedures allow a consistent method of handling transactions occurring under different circumstances or process by different individuals. Consistency in reporting also allows for comparison between reporting periods and expedites management analysis and decision. Two Bases for Accounting There are two bases that can be followed in accounting: ‘cash’ and ‘accrual.’ In general, the accrual basis of accounting is the recommended system for both municipally owned and investor-owned water utilities. Under the cash basis, revenues are recognized as being earned when payment is received, and expenses are charged when payment is made. Under the accrual basis, revenues are recorded in the period in which service is given, although payments may be received in a prior or subsequent period. Systems may also be partly cash and partly accrual; when this happens, the systems are called either modified accrual or modified cash systems. Under the accrual system, the cost of the delivery of a utility service (power, gas, or water) during the month of January, for example, is recorded as having been earned in January, despite the fact that payment for the service might not be received until the month of March. Accrual-basis expenses are also recorded in the period in which the benefits are received, although payments may be made in a prior or subsequent period. For example, if a distribution utility buys and pays for a block of power from a generator utility in January, but does not take delivery of the power until March, the transaction is recorded as a March expense, regardless of when payment was made.
SUMMARY An important challenge facing public utility managers today is the problem of capital acquisition. Until recently, economies of scale, together with mandated reserve capacity, meant that very large utility plants represented the most economical way to add capacity. Very large plants require very large amounts of outside capital. Vertically integrated, regulated utilities were seen as sound, stable long-term investments. Public utility managers have three major objectives when they plan for financial management: (1) how to increase the amount of resources available
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for operations, (2) how to maintain stable growth at rates high enough to attract equity capital, and (3) how to maintain autonomy and control over resources and operations. In utilities, the finance function requires decision-making in at least four principal areas: (1) capital structure, (2) operating expense and investment structure, (3) acquisition and cost of capital, and (4) working capital requirements. Utility accounting decisions and the production of financial reports require decision-making in five areas: (1) maintaining an historical record of all transactions, (2) designing and maintaining systems of internal controls, (3) establishing the financial basis for the regulation of rates and earnings, (4) federal, state, and local taxation, and (5) producing data that are used for gaining and maintaining investor confidence. Some key finance challenges facing utility managers are (1) planning for and acquiring financial resources, using either debt or equity or both, and (2) planning, monitoring, analysing, and reporting the use of those funds. In carrying out their responsibilities, financial managers use such tools as accounting and reporting, budgeting and forecasting, auditing and analysis, financial information systems, and custodial and resource management (including facilities maintenance, personnel, inventory control, and financial services). Accounting provides four services in utilities: (1) it maintains an historical record of the financial transactions of the firm, (2) it makes operating information available to other people in the firm for budgeting, forecasting, and performance monitoring, (3) it provides a basis for establishing a system for controls, and (4) it carries out analyses of results and produces reports on the financial health and vigor of the utility to managers, investors, and owners. Two major accounting systems are used by all sectors of the public utility industry: One, the NARUC system, is used by investor-owned utilities. The second is the GASB system, which is required for all government-owned utility organizations.
ADDITIONAL READING American Water Works Association (AWWA) (1995), Water Utility Accounting, Denver, CO: American Water Works Association. AICPA (1999), ‘Statement of governmental accounting standards No. 34 – basic financial statements – and management’s discussion and analysis – for state and local governments,’ Journal of Accountancy, 188 (October), 112–31.
11.
Challenges in managing utility human resources
A number of external forces are changing the shape of the public utility workforce. This, in turn, is presenting a number of important challenges to the practice of human resources (HR) management. The fundamental problem of simply finding enough workers with the necessary skills to replace the many aging ‘baby boom’ workers now entering retirement is certainly on the minds of most utility managers. There is no doubt that the United States workforce is changing from a majority of white males to a majority of minority males and white females. One utility industry observer has referred to this trend as the ‘biggest mega trend’ in the utility industry, and a time when utilities will soon be unable to acquire workers with the technical skills needed just to maintain the technology that has already been installed (Manning 2003). The nature of the industry itself adds to the difficulty of identifying and employing the best and the brightest of today’s college and university graduates. Deregulation, reorganization, privatization, bankruptcy, and system failure are some operational forces affecting the industry that bring prospective employees to question whether they should commit to a utility career. In addition, many utilities find themselves forced to deal with infrastructure that is aging and, in some cases, crumbling. Other forces that are re-shaping the industry include federal mandates to make expensive investments in environmental protection. Scandal and unethical behavior are additional themes seen today in many descriptions of the utility industry. This chapter will look at some of these themes in the context of their impact on human resources management in investor-owned and publicly owned gas, electricity, and water utilities.
SOME MAJOR HR CHALLENGES The public utility industry consists of an eclectic mix of private and publicly owned, regulated and unregulated, very small and very large, local and global, competitive and monopolistic organizations serving different supply chain operators in different segments of a complex industry. Utility 182
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workers run the gamut from ditch-diggers and custodial staff to nuclear engineers and highly paid chief executives. Some workers are under union contract; others are not. It is no wonder that little common ground can be found for establishing a best-practices model for human resources that can be applied across all utility operations. Human resources management involves a number of different tasks and roles. Among the most common of the tasks carried out by HR staffs are the following: ● ●
● ● ●
Locating, hiring and, when necessary, firing appropriate personnel; Developing and conducting management development and worker training programs; Constructing fair compensation plans; Determining appropriate motivational activities; Counseling workers in times of crisis.
As the twentieth century was coming to a close, the editors of Public Utilities Fortnightly (Schuler 1999) asked five human resources vicepresidents to discuss a variety of concerns that were expected to have a major impact on utility operations during the first decades of the new century. The five companies ranged in size from less than 5000 workers to more than 32 000 employees. All of the firms had recently undergone downsizing that had reduced employment by as much as 20 percent. Topics discussed included: ● ● ● ● ● ● ● ● ●
Retraining Going global Hiring specialists Tough positions to fill Elastic rosters Worker protections Union shops The hiring boom and hiring bust, and What lies ahead for utilities?
Although surveyed individually, the responses of the HR managers were remarkably similar. All were finding it difficult to fill staff needs in two areas: information systems and trading and risk management. Because the firms were facing stiff competition, the companies found themselves forced to train employees in ways to function in a competitive environment rather than the former, regulated monopoly way of doing business. Some utilities established training programs to enhance worker
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skills in both sectors of the business: regulated and competitive. Almost all of the HR managers acknowledged the continuing role of labor unions in their future employee mix. The Kissimmee Utility Authority’s (KUA) electrical utility is a typical example of the human resources function in small municipally owned utilities. KUA, with 58 000 customers in Kissimmee, Florida and surrounding areas, is the state’s sixth largest utility. The HR department manages the recruiting, staffing, safety, and communications activities. The department manages pension, healthcare, and unemployment compensation programs, and is responsible for all insurance claims against the utility. Until recently, the risk management function was also housed in the HR department, but has subsequently been transferred to the finance office (Gent 2004).
THE DISAPPEARING WORKFORCE CHALLENGE Nearly half of the utilities participating in a 2003 study by the American Public Power Association (APPA) reported that from 15 to 50 percent of their workforce will become eligible for retirement by 2006 (Burr 2004a). Shortages will occur in a wide range of key positions, but the greatest challenge will occur in finding replacements for management, administration, and technical positions. Moreover, a smaller number of engineering graduates are preparing themselves to enter the utility industry. The number of college and university degrees in power engineering awarded each year have declined from more than 2000 annually in the 1980s to less than 500 per year now. The loss of critical knowledge will likely be most painful for utilities. Staff reductions and eliminating training during cost-cutting initiatives are also contributing to the ‘brain drain’ faced by many utilities. Costcontainment and shrinking workforce programs in the 1990s have exacerbated the problems expected from the many technical and managerial workers retiring in the near future. A big part of cost containment was reductions in or, in some cases, the elimination of working training and management development programs. The following programs designed to deal with the expected worker shortages were recommended by the APPA (Burr 2004a, p. 53): ●
● ●
Track workforce statistics (mean age, age group distribution, years of service, etc.); Project retirements and identify likely talent shortages; Plan the utility’s future workforce, in light of changing organization, market, and technical needs;
Managing human resources ●
●
●
● ● ●
185
Inform internal and external company stakeholders about the issue and potential impact; Collect and record existing staff knowledge and facilitate knowledge transfer from older employees to their replacements; Recruit, develop, and retain younger workers; enhance leadership and critical skill-development programs; Where appropriate, rehire selected retirees; Slow the departure of older workers; Develop and maintain a workplace culture that promotes mutual respect among all workers.
The experience of Chelan County PUD in Wenatchee, Washington, is representative of the human resources challenges faced by public utilities (Abbott 2003). The district has estimated that over most of the first decade of the twenty-first century it will lose more than 10 percent of its workforce every year. Moreover, it expects to have the most difficulty in finding replacements for retiring skilled crafts and management personnel. In order to deal with the missing management challenge, the utility has developed a formal succession program it calls ‘Leadership from Within.’ The program was designed and is administered by the organizational development manager and the human resources management unit. The district has identified four strategic factors which it considers critical to its future success: customer service, operational excellence, environmental stewardship, and community responsiveness. The succession program covers developing eight basic competencies associated with the four success factors. It includes a compensation program that rewards individuals for what it terms value-added skills, leadership ability, and job performance. Programs function at four organization levels: the bargaining unit, the professional/technical unit, supervisors, and directors. The High Cost of Retirements Human resource departments are responsible for managing a variety of employee benefit plans. Among the most costly of these benefit programs is the retirement fund. Retirement plans for investor-owned utilities are often more complex than plans managed for employees in publicly owned utilities. This is because investor-owned utilities typically include stock purchase options in the mix of retirement benefits. Retirement benefits for employees in publicly owned utilities are often included in the larger pool of worker benefits for municipal, county, or state employees. Two investor-owned plans are discussed below: Calpine Corporation of San Jose, California, and Artesian Resources Corporation of Newark,
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Challenges to management
Delaware. The retirement plan system of the Tacoma, Washington, municipally owned utility is also described. The retirement benefits plan of the international mixed-product utility firm Calpine Corporation is typical of programs found in large utilities. Three investment plans were described in their 2002 annual report: a contribution savings plan, an employee stock purchase plan, and a stock incentive plan. The contribution savings plan, which is based on Section 401(a) and 501(a) of the Internal Revenue Code, includes deferred salary deductions, after-tax employee contributions, and profit-sharing contributions of up to 4 percent of employees’ salaries. Employees qualify for participation immediately after being hired. Profit-sharing contributions totaled $11.6 million in 2002. The employee stock purchase plan allows eligible employees to purchase common stock at semi-annual intervals through periodic payroll deductions. Purchases of up to $25 000 per year may be made. The purchase price of the stock is 85 percent of the fair market value of the stock at either the date of the employee’s entry date into the offering period, or the fair market value on the semi-annual purchase date. Calpine’s stock incentive plan provides options to purchase stock at specified prices. Options to purchase stock are vested (fully owned) after four years with the firm and expire after ten years. Artesian Resources Corporation (Artesian Resources) is a non-operating holding company with four wholly owned subsidiary companies and a onethird interest in a wastewater services marketing company. Its most important subsidiary is Artesian Water, the largest public water utility in Delaware. The regulated firm serves something like 68 000 metered customers. The human resources department manages three employee retirement benefit plans: a 401(k) salary reduction plan, a post-retirement benefit plan, and a supplemental pension plan. The 401(k) plan covers all employees. Artesian Resources (Artesian) contributes an amount equal to 2 percent of the salaries or wages of all eligible employees to the employee’s pension fund. In addition to this 2 per cent contribuing for contributions employees themselves make to their retirement plan (up to 6 percent of their salaries) Artesian will add an amount equal to half of the employees contribution. The company’s 2002 annual report noted that additional contributions of up to 3 percent of eligible salaries and wages may be made when circumstances permit (no additional contributions were made in 2002 or 2001). Artesian Resources’ post-retirement benefit plan provides medical and life insurance benefits to some retired employees. Accounting standards (No. 106) require the firm to accrue the expected cost of providing the benefit while the workers are employed. Artesian’s supplemental pension plan provides additional retirement benefits to full-time employees hired
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before April of 1994. The plan was established to help employees save for future retiree medical costs. Artesian Water contributes from 2 percent to 6 percent of the employee’s salaries and wages, based on years of service. A second version of the plan was developed for employees over the age of 50 when the plan began in 1994. The city of Tacoma, Washington, operates a public utilities department with three separate divisions. These are managed in much the same way that investor owned holding companies manage more than one subsidiary operating company. Tacoma Utilities’ three separate operating utilities include Tacoma Power, Tacoma Water, and Tacoma Rail. Tacoma Rail owns and operates a switching engine system for the transcontinental railroads serving the extensive system of port facilities and grain elevators in the city. Employees of the power and water utilities are covered by the Tacoma Employees’ Retirement System, which is a system funded and managed by the city for all employees. Covered employees are required to contribute 6.44 percent of their gross wages to the system, with the utility employer contributing an additional 7.56 percent, for a total of 14 percent of gross wages. The combined sums are invested in equity securities, fixed income securities, real estate, and short-term investments. Tacoma Utilities contributed $l1.6 million to the plan in 2002, with employees contributing $9.8 million (Tacoma Utilities 2002 Annual Report).
THE CIVIL SERVICE REFORM CHALLENGE The human resources activities of many publicly owned utilities operate under civil service system, or merit system, rules. However, over the past decade, a number of state and municipal utilities have been wrapped up in a broadly based movement for reform of the traditional merit system (Seldon et al. 2001). These reforms are most likely to fall into one of three different categories: (1) reforms designed to reduce the size and scope of the civil service by making it easier for government agencies to terminate the employment of workers, while also doing away with certain entitlement aspects of civil service; (2) reforms that promise to establish greater flexibility within the existing civil service system by delegating authority for some personnel functions to agencies and managers, cutting personnel regulations, and setting incentives for greater performance – while not doing away with core merit system principles; and (3) reforms that abolish the civil service entirely. The underlying goal of these reforms is establishing a plan for improving government performance by modernizing human resources management practices and initiating innovative personnel techniques.
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The changes taking place in government employment – including employment in publicly owned utilities – are resulting in an entirely new way of performing the personnel services that have evolved over the last 100 years. The authors of a four-year, national study described the changes in human relations systems in the following terms: The analysis of state mission statements suggests that a paradigm shift may be occurring. [Governments] appear to be replacing the bureaucratic paradigm that once dominated the culture of . . . personnel departments (consisting of bureaucracy, control, and hierarchy) with a new paradigm that emphasizes service, front-line workers, efficiency, and results. (Selden et al. 2001, p. 602)
Some of the major changes taking place in publicly owned utilities are (1) the adoption of workforce planning, (2) decentralized selection processes, and (3) simplified and more flexible worker classification systems. Changing the classification system includes reducing the number of job classifications (a process called ‘broad banding’) and new approaches to performance evaluation. The new performance evaluation systems require employees and managers to collaborate on setting performance targets which are direct reflections of agency objectives.
THE COLLECTIVE BARGAINING CHALLENGE Many employees of public utilities are employed under union contracts. As a result, union-management relations are an important part of the utility management process, and one of the most problematic challenges facing utilities managers. Public utilities, whether regulated or unregulated, investor- or publicly owned, are expected to provide their products and services at reasonable rates. Meeting union-demanded pay increases may sometimes conflict with this policy. The rate-making process may take place in open hearings, where every aspect of utility costs is open for inspection and subject to public question. At the same time, utilities are required to provide continuous service and to meet all reasonable demand for their product. If utility workers choose to engage in a prolonged strike, the ability of the utility to meet these legal requirements is severely curtailed. On the other hand, utility management may decide it is in the best interest of the utility and its customers to increase wages and benefits substantially in order to avoid a strike. Because of the monopolistic nature of the industry, utility rates of return must be maintained. Therefore, the rates customers pay for the service must be raised to pay for the labor cost increase – resulting in customer objections
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and resistance from regulatory commissions (Farris and Sampson 1973). Publicly owned utilities may not have to gain acquiescence of a regulatory agency, but must justify rate increases to their owner/customers, or management may find itself trying to avoid a voter revolt that includes but is not limited to, the recall of directors. Chief Tasks in the Labor Relations Process The two chief tasks in the labor relations process are administering existing contracts and negotiating new contracts. The administration of on-going contracts, including the handling of grievance procedures, is typically a responsibility of the human resources department. In small utilities, contract provisions may be negotiated by the managing director, a member of the legal staff, or some other member of management staff. In larger utilities, new-contract negotiations and renegotiations of old contracts are often led by a vice-president in charge of industrial relations. However, both small and large utilities may hire special consultants to carry out the collective bargaining task, thus refraining from creating unnecessary animosities as a result of negotiation breakdowns. Negotiators for the union may be either the business agent of the local union or a negotiator provided by the union’s national headquarters. Negotiating labor contracts takes place in a systematic process called collective bargaining. The intent of the bargaining process is, or should be, the amicable resolution of differences in the needs and desires of both sides. Such resolution of the conflict should be based upon an assessment of what will provide the greatest gain for all parties with a stake in the health and welfare of the utility. Negotiations are not always held in an atmosphere of cordiality and mutual respect, however. Contract negotiations have too often become acrimonious and counterproductive. One management text describes this state of affairs in the following way: ‘Near the end of negotiations, meetings may last 12 to 15 hours – and calm discussion may give way to personal insults’ (Rachman et al. 1993, p. 304). The collective-bargaining process takes place in a well-proven series of steps in which both sides participate. The process occurs in four distinct stages: (1) pre-planning, or preparing to meet, (2) meetings of both sides to present their demands, (3) reaching an agreement, (4) voting and ratification of the contract. During the preparation phase, the union team polls its members to determine their fundamental needs, which it then frames into a settlement proposal. At the same time, management seeks to anticipate the expected cost of the union’s proposals. Management must calculate at what point meeting the demands will exceed the cost of a strike. During the meeting
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phase of the process, both sides present their proposals. This is followed by negotiation by both parties until either an agreement is met or the negotiation reaches an impasse. If an agreement is not met, an outside arbitrator may be called in. Arbitrators cannot negotiate, but are empowered to study both sides of the argument and make recommendations. The decision reached by an arbitrator is binding, and the agreement must be sent to the union members for a ratification vote. If it is rejected, the parties return to the bargaining table to continue negotiating. Today, adversarial contract negotiations appear to be the exception rather than the norm. It is to everyone’s advantage to reach an agreement before negotiations break down, and without such costly actions as strikes, lockouts, slowdowns, picketing, boycotting, and similar legal, but oftendestructive, behaviors. The experience of WGL Holdings, Inc. is an example of how all stakeholders – employees, management, stockholders, and customers – benefit from non-confrontational contract negotiations. WGL Holdings is a public utility holding company serving customers in the District of Columbia, Maryland, and Virginia. Its regulated natural gas distribution subsidiary serves nearly 960 000 customers. The firm’s unregulated affiliates sell natural gas, electricity, and energy-related products and services in competitive markets. WGL described a product of its 2002 collective bargaining processes in the following way: The company’s success relies on the enterprise and efforts of its employees. Bonus opportunities related to customer service performance and safety standards are included in the three labor contracts Washington Gas successfully negotiated with utility employees this year. Performance standards also were integrated with the incentive rate plans proposed by the company in each jurisdiction. (WGL Holdings, Inc. 2002 Annual Report, p. 14)
DEALING WITH THE PRIVATIZATION CHALLENGE A major challenge facing human resources managers in municipal public utilities has been brought on by the current trend in shifting from municipal ownership and operation to privatization through partnerships with private firms. Nationally, more than 85 percent of all water utilities and 95 percent of all wastewater utilities are municipally owned. A growing number of these municipalities are privatizing their utility operations. Partnering with a private contractor may allow a municipality to reduce its costs and improve the quality of service. They are doing so because they cannot afford to fund needed expansion to meet demand growth and to pay for the improvements required by new regulatory laws demanding cleaner, safter systems. The water utility industry has estimated that needed rebuild-
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ing and repair of water and wastewater systems in the U.S. will cost in excess of $300 billion (Ruth 1999). Employees at many municipal utilities are government employees and enjoy all the protections and benefits, including the medical and retirement programs, of their fellow municipal workers. Many are members of strong, municipal-employee labor unions. What happens to these employees when operation of the system is given over to a private firm has been a major concern, both to the employees and their labor unions. An example is the City of Perth Amboy, New Jersey, which entered into a 20-year contract with Middlesex Water, a British utility management firm, to manage the city’s water services. By following the lead of this partnership program, some of the fears shared by employees were addressed, as the following report suggests: A lot of times people look at public and private partnerships [as a ploy] to squeeze out the public employees because they believe they are the liability, but they are not. They [simply] need the private sector approach to management, particularly in a regulated industry, to make things work more smoothly. Middlesex Water allayed those fears in its deal with Perth Amboy by using the preexisting staff to do the work . . . What really made the transition so seamless was that [the private contractor] kept all the employees. (Ruth 1999, p. 18)
THE CHANGING ROLE OF HUMAN RESOURCES MANAGEMENT In both investor-owned and publicly owned utilities, the human resources function is undergoing a dramatic shift of role and function. The following statement describes the changes in human resources management (HRM) in business and all levels of government; it is clearly applicable to all levels of the public utility industry: HRM is presently experiencing a near revolution in its operating practices. Cherished techniques are reportedly being abandoned, and a profusion of new approaches to the HRM function is taking hold within the personnel profession. Persuasive control techniques are yielding to a consultative role for the personnel office. HRM is purportedly being viewed as a strategic staff enterprise aligned with organizational values, mission, and vision. Personnel functions are being decentralized to lower levels of public organizations. (Hays and Kearney 2001, p. 586)
Four years earlier, the vice-president of PECO Energy, Inc., William Kaschub, used similar concepts to describe the redesign of the HR function then taking place at the Pennsylvania investor-owned electric utility
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(Kaschub 1997). PECO Energy is part of the Exelon Corporation, which was formed in 2000 through the merger of PECO Energy of Philadelphia, and Unicom, the Chicago parent company of Commonwealth Edison, which serves the Northern Illinois energy market. PECO remains an energy services company with 1.5 million electricity and 430 000 natural gas customers in Southeastern Pennsylvania (Exelon 2002). In 1995, PECO Energy’s six business units were restructured in response to deregulation of the power industry, with mandated competition. PECO’s central human resources division was the only unit left unchanged during the first phase of corporate restructuring. However, it was soon apparent that HR operations as they then existed could not continue to function as it had in the past. The unit not only had to become more cost-effective in its day to day operations, it also had to become more efficient in the ways it met the HR needs of the re-engineered divisions. In comparison with industry standards, the unit was considered overstaffed. Yet, it was still having difficulty dealing with the large number of individual-employee transactions demanded by the six divisions. The divisions continued to rely on the corporate HR staff for services that, using readily available information technology, they could have more easily performed themselves. At the time, the HR department included a staff of 230 people, or one HR staff person for every 35 employees. In addition, the out-dated grievance process required job supervisors to acquire HR approval before censuring employees, and the hiring process was badly in need of change. The utility began a comprehensive, four-phase, employee-centered reorganization program that was designed to change the transactional focus to become what Kaschub (1997) described as a ‘unit of strategic senior consultants who coach and guide, but do not manage. The new vision, that all employees are accountable for themselves, is what now makes everyone responsible for the successful operation of PECO.’ The four phases included (1) visioning, (2) process design, (3) organizational design, and (4) implementation and planning. Rotating groups of 200 employees, representing every level of the firm, participated at each meeting. Eventually, nearly 800 employees were involved in the final shaping of the PECO human resources mission, vision, process, and organizational culture. The transactional process was replaced with a computerized call center, which was expected to meet 80 percent of employees’ information needs, which center on benefits updates, retirement plan information, and policy guidelines. The HR staff has been freed to serve strategically as consultants when great needs arise. KBC Advanced Technologies, Inc. is an independent process engineering group serving utilities from offices in the United Kingdom, the United States, Singapore, Japan, and the Netherlands. Box 11.1 displays the
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company’s enlightened approach to human resources management as spelled out in its 2002 annual report.
BOX 11.1
KBC ADVANCED TECHNOLOGIES’ HUMAN RESOURCES POLICIES
The group continues to place a high emphasis on attracting, retaining and developing employees to achieve the Group’s business plan objectives. The Group pursues an active policy of employee involvement and development, including communication through staff meetings, written communications to all staff, internal newsletters and use of the Group’s intranet. Employees are provided with information on matters affecting them as employees, on developments within the business and on the various factors affecting the Group’s performance. Group policies and practices are continually reviewed and improved as required to meet the needs of employees and the business. The Group is committed to providing equality of opportunity for all employees and in particular ensures that fair selection and development procedures apply. The aim of the Group’s policy is to ensure that no job applicant or employee receives less favorable treatment than any other on the grounds of age, sex, sexual orientation, disability, marital status, color, religion, race or ethnic origin. The Group encourages the involvement of employees in the Group’s success through a share option scheme, as well as a bonus scheme which emphasizes performance and delivery of business plan objectives. There is a formal reward and recognition program to encourage and reward outstanding employee and team performance on a quarterly basis. The program provides cash awards, which are separate and distinct from salary, and formally recognizes employees who make a specific, extraordinary and measurable contribution to the profitability, productivity or efficiency of the Group. Source: KBC Advance Technologies, plc, Annual Report and Accounts 2002 p. 18.
Hays and Kearney (2001) surveyed a final sample of 295 members of the International Personnel and Labor Relations Association and the Section of Personnel and Labor Relations of the American Society for Public Administration. The sample was asked to rate the then-current (1998) importance of 80 personnel techniques and activities, and to then project how
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important they believed those same activities would by 2008. Respondents reported little or no difference in the predicted importance of such activities as staffing, responding to agency and department heads, benefits administration, pay administration, and developing HRM policy. Activities that were considered to be of little importance in both periods included responding to requests from elected officials, processing grievances, engaging in collective bargaining, and administering labor contracts – an indication that labor union influence will continue its decades-long decline.
SUMMARY A number of external forces are changing the shape of the public utility workforce. This, in turn, is presenting a number of important challenges to the practice of human resources management. The United States workforce is changing from a majority of white males to a majority of minority males and white females – a change that one utility industry observer has referred to as the ‘biggest mega trend’ in the utility industry, and a time when utilities will soon be unable to acquire workers with the technical skills needed just to maintain the technology that has already been installed. Deregulation, reorganization, privatization, bankruptcy, and system failure are some operational forces affecting the industry that bring prospective employees to question whether they should commit to a utility career. Many utilities find themselves forced to deal with infrastructure that is aging and, in some cases, crumbling. Other forces re-shaping the industry include (1) federal mandates to invest in environmental protection, (2) corporate scandal, and (3) unethical behavior by senior and mid-level managers. Five human resources vice-presidents identified the following concerns that were expected to have a major impact on utility operations during the first decades of the new century: retraining, going global, hiring specialists, tough positions to fill, elastic rosters, worker protections, union shops, the hiring boom and hiring bust, and what lies ahead for utilities. The HR managers were finding it difficult to fill staff needs in two areas: information systems and trading and risk management. Because the firms were facing stiff competition, the companies also found themselves forced to train employees in ways to function in a competitive environment. Some utilities estalished training programs to enhance worker skills in both sectors of the business: regulated and competitive. Almost all of the HR managers acknowledged the continuing role of labor unions in their future employee mix. Utilities participating in a 2003 study by the APPA reported that from 15 to 50 percent of their workforce will become eligible for retirement by 2006. Shortages will occur in a wide range of key positions, but the greatest
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challenge will occur in finding replacements for management, administration, and technical positions. Moreover, a smaller number of engineering graduates are preparing themselves to enter the utility industry. Retirement plans for investor-owned utilities are often more complex than plans managed for employees in publicly owned utilities. This is because investor-owned utilities typically include stock purchase options in the mix of retirement benefits. Retirement benefits for employees in publicly owned utilities are often included in the larger pool of worker benefits for municipal, county, or state employees. The human resources activities of many publicly owned utilities operate under civil service system, or merit system, rules. However, over the past decade, a number of state and municipal utilities have been wrapped up in a broadly based movement for reform of the traditional merit system. Some of the major changes taking place in government-owned utilities are the adoption of workforce planning, decentralized selection processes, and simplified and more flexible worker classification systems, including reductions in the numbers of job classifications, and new approaches to performance evaluation. Many employees of public utilities are employed under union contracts. As a result, union management relations are an important part of the utility management process, and one of the most problematic challenges facing utilities managers. The two chief tasks in the labor relations process are administering existing contracts and negotiating new contracts. The administration of ongoing contracts, including the handling of grievance procedures, is typically a responsibility of the human resource department. Negotiating labor contracts takes place in the systematic process of collective bargaining. The intent of the bargaining process is, or should be, the amicable resolution of differences in the needs and desires of both sides. The collective-bargaining process takes place in a well-proven series of steps in which both sides participate. The process occurs in four distinct stages: (1) pre-planning, or preparing to meet, (2) meetings of both sides to present their demands, (3) reaching an agreement, (4) voting and ratification of the contract.
ADDITIONAL READING Gomez-Mejia, Louis R., David B. Balkin and Robert L. Cardy (2001), Managing Human Resources, 3rd edn, Upper Saddle River, NJ: Prentice Hall. Lauer, William C. (ed.) (2001), Excellence in Action: Water Utility Management in the 21st Century, Denver, CO: American Water Works Association. Starling, Grover (1998), Managing the Public Sector, 5th edn, Fort Worth, TX: Harcourt Brace.
12.
Challenges in public utility governance
For the first time since the mid-1930s, the question of governance has once again become an issue in public utility management. A new wave of stockholder activism is underway, driven by large institutional shareholders who charge that corporations have not gone far enough in their efforts to ensure good governance. The utility industry, as much or more than some other industries, has had to endure the same scandals that have struck corporate America since the late 1990s, including improprieties in accounting, market manipulation, and executive corruption. In addition, demands for improvements in corporate governance have also been made by state public utility commissions. Some commissions have proposed regulatory changes that directly hit at governance policies and actions (Finon et al. 2004; Genieser 2004). Keohane and Nye (2000, p. 12) defined governance as ‘the processes and institutions, both formal and informal, that guide and restrain the collective activities of a group.’ That definition is used here to refer to the internal and external exercise of direction, control, management, and policy shaping of all sectors of the public and investor-owned utility industry. Governance is not, and never has been, a static principle. Demands for change and more or less control over utility governance have been aired over three major waves of activism. These demands first appeared during the Progressive Era and reached their peak during the early 1900s with the trust-busting activity of President Theodore Roosevelt’s Administration. At that time the issue was at the top of proposed reforms of the American economic system. The drive for better governance had already seen the passage in 1887 of the Act that established the Interstate Commerce Commission and near unanimous passage of the Sherman Antitrust Act of 1890 (Bruchley 1990). The second coincided with the Great Depression of the 1930s. The stock market crash of 1929 brought about the failure of many firms – including a number of large public utility holding companies. Demands for better governance resulted in passage of the Securities Exchange Act in 1934 and the Public Utilities Holding Company Act in 1935. 196
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The third wave in governance reform began during the 1980s with restructuring of the industry. It reached its apex with the California deregulation failures in 2000 and 2001 and the collapse of Enron, once the largest energy trading company in the world. Until the first few years of the twenty-first century, the trend in public utility governance was leading away from government ownership and control toward deregulation and privatization of government-owned systems. Since then, restructuring and its controversial offspring – deregulation – are definitely on hold. They may remain so for the foreseeable future. Governance of public utilities in the United States may be the most complex of all industries. To begin with, ownership of utilities is shared by two very different enterprise forms: private, investor-owned corporations, and at least three different publicly owned organization forms. Investor owned utilities and a few large municipally owned utilities serve customers in most urban areas. Two examples of large municipal operations are the power and water utilities in the Washington State cities of Seattle and Tacoma (in both cities, however, natural gas service is provided by investorowned utilities). Until the energy problems that occurred in California during 2000 and 2001 and the regional blackout that occurred in Northeastern US and Canada in 2004, it appeared as if some municipally owned utilities would follow the few who had elected to continue to own their utility systems, but contract with private companies for system operations. Many of the private contractors have had considerable experience in contract operation in Europe, South America, and elsewhere. However, the trend toward deregulation in the utility industry has slowed as a result of the difficulties in California and the Northeastern US and Canada. Other than municipals the most important types of publicly owned utilities are Public Utility Districts (PUDs) and Consumer Cooperatives (Coops). PUDs are special independent local taxing districts; they are governed by three-to-five directors elected by all voters in the district they serve. The board of directors provides policy guidance and employs operating personnel. Co-ops are similar to mutual insurance companies or farmers’ cooperatives; they are owned by the customers they serve. PUDs were formed during the 1930s to distribute and market the power produced by large federal hydroelectric projects, most of which are located in the far western United States. The consumer cooperative enterprise form has existed for many hundreds of years and was one of the earliest ways of developing utility and transportation infrastructure in North America. Both PUDs and Co-ops may provide electricity, natural gas, or water – or all three – but are most commonly found in the electric power sector of
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the utility industry. As electricity utilities, they most often operate as local distributors of their products, but a few also have some generation capacity or, until recently, may have also owned and operated some long-distance transmission lines. With the availability of small, efficient gas turbine power generators, more PUDs and Co-ops have installed one or more of their own small generating plants to meet their peak load demands, when prices for power purchased on the open bid market can be whatever the market will bear. About 25 percent of the US population receives their power from PUDs, whereas Cooperatives provide power to about 12 percent of the population. PUDs are found mostly in the Pacific Northwest of the United States. Cooperatives are most often found in rural areas in the American Middle West, where they serve customers in eight out of every ten counties. Co-op customer density is something less than seven customers per mile of distribution line, compared with the 34 customers per mile for the average investor-owned power utility that operates in more suburban or urban service areas. Because their customers are relatively large distances from one another, Co-ops own and maintain some 43 percent of all the distribution lines in North America. Control by Local Authorities In urban areas, governance in the public utility industry is most often exercised through state and local regulatory authorities controlling the operations of private or investor-owned utilities (IOUs). IOUs serve about 75 percent of the population. Ownership of water and wastewater utilities has, until recently, generally followed a municipal or mutual society-owned model. Today, however, many of these systems have been sold or leased to private operators, while in others a number of traditional utility services are now contracted out to the public sector – the controversial practice of outsourcing. Governance is the term used to define the process of managing the operations of organizations and their relationships with their internal and external stakeholders. In most industries strategy is decided by directors and senior officers, while the responsibility for carrying out operations is delegated to managers and supervisors. These operators are generally free to run the organization without fear of excessive external interference from government. The picture is different in the utility industry, however. This industry is made up of a variety of public and private participants. Investors, voters, individual citizens, and government enterprises also play a role in industry governance. In addition to the private and public delivery organizations, a multi-organizational variety of federal, state, and local
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government agencies regulate and oversee operations. These agencies have the power to monitor and approve or deny the investment decisions of investor-owned utilities to set rates; they must also approve what returns on investments are allowed and can force utilities to install environmental protection equipment. In the electricity and natural gas industries and an increasing number of water services, the majority of organizations are investor-owned utilities. Most private utilities are organized as corporations. In corporations, owners of common stock have the right to elect their representatives to the corporation’s board of directors. Board members are responsible for monitoring, directing, and appointing the firm’s top managers. In this way, shareholders are able to set the direction for the corporation, evaluate the performance of managers, and control the distribution of the corporation’s profits. The board has the right – and the obligation – to remove poorly performing managers (Lashgari 2004).
CONSOLIDATION SHAPES INDUSTRY GOVERNANCE Utilities have traditionally been among the nation’s most capitalintensive industries. Until recently, very large facilities were constructed so as to benefit from perceived economies of scale and provide the mandated excess capacity to cover future growth and potential spikes in demand. Only public agencies and large public service corporations are able to acquire the large amounts of capital needed for the large projects. In the early history of the industry, mergers and acquisitions brought together the many small, competing utilities that once characterized the industry into very large, connected ‘natural monopolies.’ This early integration of the private utility industry was nearly completed by 1910 (Glaeser 1957). Eventually, these consolidated monopolies grew into very large, often national, monopolies. The next step in industry consolidation involved widespread expansion of the utility holding company concept. Holding companies are corporations that are organized to own the stock of other companies or corporations. Holding companies are not operating companies, although a holding company can own the common stock and other securities of one or more operating companies. In this way, holding companies are able to control the operating company’s policies and operations. Box 12.1 describes a typical modern utility holding company and its subsidiaries.
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BOX 12.1
SOUTH JERSEY INDUSTRIES: A TYPICAL UTILITY HOLDING COMPANY.
South Jersey Industries, Inc. (SJI), of Folsom, New Jersey, is an energy services holding company with four wholly owned energy subsidiaries and one joint venture. South Jersey Gas Company, a regulated natural gas operating company, is the core operation in SJI’s business. This subsidiary delivers natural gas to nearly 300 000 residential, commercial, and industrial customers in the seven southern counties of New Jersey. Through its Gas Supply and Off-System operations, South Jersey Gas also sells natural gas to wholesale customers in the interstate market and manages the subsidiary’s pipeline and storage facilities. A separate operation provides repair to household and commercial appliances on a competitive basis. South Jersey Energy Company (SJE), the second subsidiary, acquires and markets natural gas to retail end users and provides energy management services to commercial and industrial customers. SJE has one subsidiary, SH EnerTrade, which provides energy services to the Atlantic City casino industry and markets an air quality monitoring system. The third subsidiary is South Jersey Resources Group. This business markets wholesale gas storage and transportation in the mid-Atlantic and southern states. The Resources Group also conducts price-risk management activities. Marina Energy, SJI’s fourth subsidiary, develops and operates energy-related projects in southern New Jersey. A recent project of this firm was development of a cooling, heating, and hot water facility for an Atlantic City resort. Finally, SJI is a joint-venture partner with Conectiv Solutions (the electricity provider) in Millennium Account Services, a contract meter reading company that serves both partners throughout southern New Jersey. Source:
South Jersey Industries, Inc., 2002 Annual Report.
To gain control, the holding company need only control a simple majority of the voting stock of the subsidiary. Control can also be gained by minority owners through the use of the proxy system. Under the proxy system, the many owners of operating company stock were encouraged to give their proxy (that is, assign over the right to vote their shares at stock-
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holder meetings) to some representative of the company – usually the holding company’s officers or directors – who could then vote anyway they wanted to on issues brought before the board. By collecting the voting rights of a majority of company shareholders (many of whom may have owned only a few shares), management was able to gain control of the company’s operations. The proxy system is completely legal and continues to function today, although the numbers of levels in a holding company system and all financing schemes are controlled by the SEC. Therefore, the ‘capital’ of a holding company is not any actual physical property, patents, or other similar assets, but is instead the stocks and bonds of other companies or corporations. According to Bruchley (1990), the growth of holding companies was the chief contributor to the giant wave of mergers that hit American industry from 1895 to 1904. Holding companies were involved in 86 percent of all the mergers during that brief period. Individual firms that are absorbed into the holding companies retain their own name and focus of operations. The holding company’s chief source of earnings is the dividends paid by the controlled operating company. During the peak of their popularity before the Great Depression, some holding companies were also able to use their captive ownership relationship to charge their subsidiaries excessive fees for services such as engineering, management, and financial support. In 1934, the Securities and Exchange Commission was given the responsibility of monitoring and controling the abuses that existed in the system. In 1935, holding companies were limited to ownership of just four levels of subsidiaries. Today, holding companies are again becoming important participants in the utility industry. The Energy Act that is expected to be passed in either 2004 or 2005 includes provision for abolishing the Public Utility Holding Company Act of 1935 (PUHCA). That federal law made it necessary to gain approval of the U.S. Securities and Exchange Commission (SEC) before any holding company acquisitions could take place. SEC approval is also required for issuing new stock and other financial transactions. If repeal of the PUHCA does occur, a new wave of holding company acquisitions is expected to follow; there are mixed expectations about what the effect this will have on the industry (Genieser 2004).
GOVERNMENT’S ROLE IN UTILITY GOVERNANCE Government’s involvement in utility governance functions on three levels: federal, state, and local. The federal government owns and operates the nation’s largest power generating plants and conducts most investigations
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of private company operations and alleged fraud. It also regulates the issuance of securities, controls and issues permits to build hydroelectric facilities on navigable streams, and is responsible for the locating and construction of nuclear generators. State governments exercise most direct rate regulatory authority. Only a few state governments actively participate in one or more sectors of the delivery of utility services. The New York State Power Authority (NYSPA) was created in 1931, primarily to handle power produced from the St. Lawrence River Project developed with Canada. The NYSPA also produces power from the Niagara River. A similar Authority was formed by South Carolina in 1934 to handle power from the Santee-Cooper Project. Both Texas and Oklahoma established public agencies in the 1930s to build and operate hydroelectric plants. The greatest commitment to public power is found in Nebraska, where public ownership of all electric utilities exists. Nebraska created a Consumers Public Power District in 1939, and then set out to acquire existing private facilities. By 1946, all power distribution in the state was under public ownership. Municipal governments still own many utility systems, mostly in the distribution segment of the industry. Few municipalities produce their own power, purchasing it instead from either public or private producers. They do, however, own and operate much of their water and wastewater systems, although wastewater systems are more likely to be regional in scope today. Municipalities also issue franchises and permits to private companies and non-municipal public utilities for the use of the public rights-of-way. In the 1920s, some 3 000 municipal systems operated in the U.S.; their numbers declined from then on, although a renewed interest in municipal ownership of utilities, and particularly electric power utilities, appeared for a period during the 1930s. In addition to the collapse of the holding company pyramids, several other factors contributed to this renewed interest (Farris and Sampson 1973): ●
●
●
The development of diesel engines made it possible for municipalities to install relatively inexpensive, small generating plants, several of which could be strategically placed throughout the community. Low-priced federal power became available in much of the country. Federal power also includes preference clauses that favor public purchasers. This greatly stimulated the growth of public utility districts throughout much of the Pacific Northwest. The 1929 stock crash resulted in the collapse of many of the pyramided utility holding companies. This caused many small stockholders to lose all their savings. As a result, there was a strong reaction against the abuses of holding company executives.
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By the 1970s, only 2 000 municipalities in the U.S. sold electricity – more than 1 000 fewer than the number of city-owned systems that existed during the 1920s peak. Their numbers have continued to decline. Most water and wastewater systems remain under municipal ownership, however. How the System Evolved The complex governance system of federal, state, and local governments exercising some level of control over both public and investor-owned utilities has evolved over six different periods (Dimock 1935). The first was the granting of charters by colonies and later by individual states. This period, which lasted until after the Civil War, was characterized by corruption and misuse of rights granted by those charters. Municipalities had little or no control over the companies receiving the charters. Eventually, widespread dissatisfaction with this system led to demands for home rule and municipal ownership. The second phase lasted through the decade after the Civil War, and featured passage of state laws that set minimum standards with which charter recipients had to comply. In the third phase, which began around 1875, home rule charters were finally granted to larger municipalities; cities could now develop and operate their own utility systems. During this period, public ownership advocates based their arguments on two chief premises: First, public ownership would provide essential public services to everyone without enriching any particular individual or group at the expense of others. Second, with public service as the driving force in place of profits, service would be made available to everyone, not just to a select few. Passage of the Act establishing the Interstate Commerce Commission in 1887 ushered in the fourth phase. At the close of the 1800s, there were few investors willing to make the investment needed to finance the building generating facilities, stringing power lines, building dams, and installing water lines. As a result, gas lights and electric power were available almost exclusively in larger cities, where business and industries could benefit from its use, and a small number of wealthy, private citizens could afford the cost. This period saw more states establishing regulations to control specific public services, beginning with the railroads. When the U.S. Supreme Court upheld the first test case in Illinois (Munn v. Illinois, 1877), government’s involvement in the governance of all public utilities took a big step forward. In deciding the case in favor of Illinois, the Court referenced a 1676 study by the Lord Chief Justice of England. The British Justice found that if a privately owned wharf was one
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that all persons used for loading and unloading, it thus became ‘affected with the public interest,’ and just and reasonable rates had to be charged for its use. The U.S. Court found the privately owned grain elevators in the Illinois case to be affected with a similar public interest; the grain elevator was, in effect, a public warehouse (Glaeser 1957). The fifth step in the evolution of government involvement in utility governance began in the first decades of the twentieth century. By that time many states had established formal public utility commissions and set about establishing standards they hoped would control any potential misdeeds by private firms. The federal government’s participation in the ownership and governance of electric power facilities and the private utility sector really took off during the administration of President Theodore Roosevelt. According to Charles Warren (1928), from 1873 to 1888, the U.S. Supreme Court heard only 70 cases relating to the government and public utilities. But from 1888 to 1918, a period roughly corresponding to the Progressive Era, the Court heard 725 such cases. The seeds of the disaster that ultimately led to the collapse of many utility holding companies sprouted in earnest after the end of World War I. The 1920s were a period of relative affluence for the urban populations of the United States. Both private and public power utilities expanded their generating and distribution facilities as quickly as they found the money to do so. Municipal water and sewer utilities were also driven to expand as more of the rural population moved into the nation’s cities. Despite their frenzied efforts, utilities were hard pressed to keep up with the growing demand for power and water. Partly to secure the investment funds they needed for expansion and partly to consolidate their financial gains, many of the investor-owned power companies joined together to form giant, many-layered holding companies. Many municipal systems, which were often ‘pathetically antiquated and inefficient,’ also needed investment. However, some political leaders, tired of the responsibility of meeting the never-ending demands for power, water, and wastewater treatment facilities, sold out to private firms. Thus, the 1920s experienced a net decline in public ownership (Sparks 1964). The sixth stage began with the economic upheaval that followed the stock market crash in 1929. This stage saw the direct government involvement in all sectors of the industry. Under the New Deal programs of President Franklin Roosevelt, the federal government constructed the Tennessee Valley Authority project, went ahead with the Hoover Dam on the Colorado River, and built the dams on the Columbia River that became the heart of the Bonneville Power Administration. Included in these and other federal developments were extensive land reclamation projects and
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irrigation systems that distributed the water stored behind the huge new dams. More importantly to a large segment of the population at the time was establishment of the rural electrification program, which eventually brought electric power to farmers all across the country. The major New Deal legislation firmly establishing federal control over the utility industry was the Public Utility Holding Company Act of 1935 (Koontz, 1941). Prior to this, federal control had only been marginal at best. It was based on provisions in the Water Power Act of 1920, which was concerned primarily with conservation and control of hydroelectric plant locating and construction. The 1920 Act created the Federal Power Commission (FPC), which remained in effect until it was replaced in 1935. Today, publicly owned utilities serve something like 25 percent of the electricity market. These include municipal operations, cooperatives, and a few mutual operations. Most of these operations are small; less than half produce their own power. Instead, they still purchase federally produced power for resale. Recent changes in the federal government’s preference clause system have opened up this market to investor-owned utilities as well. This is cause for considerable concern to publicly owned utilities who initiated lawsuits to reverse the decision.
MODELS OF UTILITY GOVERNANCE Birchall (2002), a critic of utility restructuring and privatization, has identified six separate utility governance models prevalent today, four of which lie between what he termed ‘the extremes’ of private ownership on one hand, and public ownership on the other. In between these poles are the following four ownership variations: (1) a nonprofit trust or company, (2) a public interest company, (3) a consumer mutual society, and (4) a public authority (such as the New York Water Authority). Nonprofit trusts function in much the same manner as for-profit organizations. They have the same ability to turn to the bond market to raise long-term capital. They can also borrow from banks for short-term funding. Often, prices charged by nonprofit trusts for services are the same or somewhat less than prices charged by investor-owned firms for the same or similar services. Like all businesses, nonprofit trust organizations must retain some surpluses for future expenses. However, because low earnings are necessary to keep their federally granted nonprofit status, a key objective of these organizations is to avoid earning greater than minimally needed profits. Finally, a nonprofit trust can issue membership shares. Therefore, its governance can become widely community based. As more
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shares are issued in the community, the more this model comes to resemble a mutual society. Public interest companies are designed to reap the social benefits of public service with the economic benefits of entrepreneurship. Like a nonprofit, the public interest company has public benefit goals permanently etched into its charter. However, this type of organization is also able to distribute surplus earnings to investors or entrepreneurs. The public interest company is a model that is sometimes used for governing water and wastewater utilities. The Mutual Society or Co-Op Form of Governance The mutual society form of utility governance is a form of the basic consumer cooperative (co-op). The co-op model has its roots in associations of farmers and ranchers in the Western United States that were set up to construct irrigation projects. Many farm cooperatives still provide an important function in the supply and distribution of agricultural products and for the marketing of farm products. The co-op model adopted by nearly all early rural utility organizations in the United States is similar to a model that was common across Europe before the wave of privatization programs that have been seen in the past 25 years or so. The governance of rural electricity co-ops is shaped by these seven principles of the cooperative movement (Basin Electric Power Cooperative 2004): 1. 2. 3. 4. 5. 6. 7.
Voluntary and open membership Democratic member control Member economic participation (members contribute equally to the cooperative capital) Autonomy and independence Education, training, information for managers and employees Cooperation among cooperatives Concern for the (sustainable development) of the communities they serve
Box 12.2 describes the operations of Basin Electric, a consumer-owned regional cooperative that produces power for 124 other co-ops, manufactures gas from coal, and is also involved in the competitive retail distribution of electricity. BEPC is a cooperative of cooperatives. The co-op operates coal-fired electricity generating plants with a total capacity of 3373 megawatts, the power to it provides to the 124 rural electric cooperatives serves in turn, 1.8 million consumers in nine states from North Dakota to New Mexico.
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BOX 12.2
207
GOVERNANCE IN A LARGE REGIONAL POWER COOPERATIVE
Most power co-ops are small, local organizations, unable to enjoy any economies of scale. All decisions are made by elected board members. This local control has been one of the strengths of the cooperative system. However, local control may now be limiting the co-op’s ability to achieve its primary mission, that of providing its customers reliable power at the lowest possible price. Some are arguing that co-ops are wasting their customer-owners’ money by not consolidating and economizing administrative costs. Critics of the system point to Basin Electric Power Cooperative (BEPC) in Bismarck, North Dakota, as an example of the new collaborative model emerging in the co-op governance picture. Much like an investor-owned holding company, BEPC controls five subsidiaries: Dakota Gasification Co., which produces gas by a coal gasification process to produce chemicals and fertilizers; Dakota Coal Co., which purchases coal for its power plants and owns a lime processing plant; Basin Telecommunications, Ind., which provides customized Internet service through BTInet; Basic Cooperative Services, which owns and manages properties in North Dakota and Wyoming, including reclamation maintenance of a former mine; and Granite Peak Energy, Inc., a for-profit subsidiary for marketing electricity in Montana under that state’s 1997 customer choice program. Consolidation is definitely the wave of the future for cooperatives. According to Michael Burr (2004a): ‘The world is changing around electric cooperatives, and in time they will be forced to adapt to these new environments.’ BEPC is involved in two examples of changes underway in this sector: BEPC has joined with three other utilities – two municipals and one investor-owned – to conduct a transmission study to help establish the best location for a new 600megawatt coal-fired power plant and a 100-megawatt wind farm. DEPC also joined a group of 550 U.S. cooperatives in 1998 to form a nationwide alliance, Touchstone Energy, which provides a retailmarketing resource for co-ops expecting to face retail competition. Source: Michael T. Burr, 2004a, ‘Consolidating co-ops’ and BasinElectric.com, accessed 21 June, 2004
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Mutual Societies and Public Authorities Mutual societies are similar to consumer cooperatives. Mutual societies are registered as businesses, but only for specific purposes. Mutual societies are owned by their customers. Each customer has an equal voting right, thus making it difficult for any single individual or group to gain control of the operation. Directors are elected by the membership. Earnings surpluses are distributed to members as annual dividends or percentage discounts on future purchases. Dividend amounts received by utility customers are based upon the amount of business done with the society, not on ownership. This governance model is very popular in the United States, where there are nearly 1000 electricity co-ops and more than 700 telecommunications co-ops. Although almost all of these co-ops operate in rural areas, suburban sprawl and the move of industry to rural sites have seen some of their service areas become more urban than rural. Public authority utilities are quasi-governmental institutions established specifically to provide one or more public service to customers within a specific – often regional – taxing area. Authorities have the same power to tax property in their service areas as do other levels of government. However, they function independently of all other government jurisdictions in their service area. Authorities also have the power to sell bonds in the same way that local governments issue bonds to finance infrastructure development and to borrow on the value of the property in their service area. This model has become a popular substitute for the privatized utility model initially proposed in the 1980s in Great Britain. Until 1996, most water and wastewater services in the United Kingdom were the responsibility of municipal or other local governments. When the national government decided to restructure the water utility industry, some water services were sold to private firms, while others adopted alternative ownership models. In Scotland, for example, municipal water utilities were transferred to three regional public water and sewer authorities. These were later merged into a single national public water authority that provides water and wastewater services to all of Scotland.
THE EVOLUTION OF PUBLIC OWNERSHIP OF UTILITIES The public ownership of utilities has a long and controversial history. For most of recorded history, only large central governments had the power and ability to muster, direct, and control the resources needed to build and maintain large-scale public services. Federal, state and local government
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control of utilities may have begun with the need for collective action for the erection of public monuments, such as the pyramids, and for public works, such as harbors, bridges, roads, grain storage, and irrigation systems. Government participation in these early infrastructure projects was common in Mesopotamia, India, Egypt, Greece and Rome, and early nation states. They were commonplace in colonial and revolutionary North America, as well, where collective action was needed to build the first roads, waterways, and a few municipal water systems. When public expenditure began to supplant private development of public utilities, however, controversy erupted. The battle to halt public participation in the industry turned to the courts (Farris and Sampson 1973; Bruchley 1990). Public ownership advocates prevailed, when in 1892 the U.S. Supreme Court upheld a municipality’s right to establish its own coal gas lighting utility over the protest of a privately owned firm that had been supplying the city’s gas needs for many years. The next important case occurred in 1903, when the court upheld the right of a municipality to maintain and operate its own electric utility. The following year saw a similar decision in a water utility case. Shortly afterward, court decisions upheld the rights of cities to maintain and operate public fuel yards. In 1934, the court upheld the right of a city-owned utility to operate without making a profit, even though it was competing with a privately owned utility that paid taxes to the city. The rights of individual states to establish regulatory commissions quickly followed. Federal ownership of utilities did not become an important issue until the 1930s, when it was determined that the federal government is no more constitutionally limited than were state and local governments. In determining the constitutionality of the federal government’s Tennessee Valley Authority (TVA) program, the Court found that the Constitution neither specifically says that federal ownership of a utility is permitted or forbidden. As a result, there was no constitutional basis for halting development of the project. The right of a federal agency to issue municipal revenue bonds to finance electricity plants and distribution systems was also upheld. The federal government’s development of power projects and the sale of power can be traced to the Reclamation Act of 1906. The Act states that whenever developing a power source is needed for irrigation, or when power generation is developed in association with a reclamation project, the Secretary of the Interior may sell any excess power. In such cases, municipalities always have preferred rights to purchase any of this ‘excess’ power. The federal government did not become involved in power production on any large scale until 1928, when passage of the Boulder Canyon Project
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Act of 1928 authorized construction of the Hoover Dam on the Colorado River. Water stored behind the dam was to be used for irrigation, domestic water supplies, and electric power generation. When TVA was organized as a government corporation in 1933, it included strong elements of regional development, improvements in land use, reforestation, and creation of employment. It also included flood control and navigation improvement as goals. The Bonneville Power Administration Act of 1937 was charged with encouraging the widest possible use of all electric energy that could be generated and marketed from dams on the Columbia River. In sum, the chief reasons that supporters put forth for public ownership of public utilities include the following: ● ●
● ● ● ● ● ●
Public ownership permits lower prices to consumers; Publicly owned utilities generally have a lower rate base upon which to calculate rates (they do not include federal dams for water storage and power generation in their calculations); Public ownership has lower executive salaries; Public ownership has lower financing costs; Public ownership has lower advertising and public relations expenses; Public ownership has no costs for regulation; Public ownership has no need to distribute profits; Some also say that public ownership often has better labormanagement relations.
Advocates of investor-owned utilities counter the lower cost arguments of public power supporters by contending that private ownership contributes to the economic health of a community or region through taxes and wages. As a result, private ownership should not be compared with publicly owned utilities. Moreover, investor-owned utilities are required to pay both income and property taxes and, in some cases, franchise fees as well. Publicly owned utilities pay some fees, but little or no income or property taxes. In addition, low financing cost may be more of a detriment than an advantage because it can lead to uneconomic overexpansion and resource misallocation (Farris and Sampson 1973). Money borrowed for utility expansion limits the amount that the municipality can borrow for other needed programs. This argument is often used to support the privatization and outsourcing movements that now characterize the utility industry. Private ownership advocates also contend that advertising promotes better utilization of facilities and sends messages encouraging conservation; and, that there is no proof that labor–management relations are better under public ownership. Because investor-owned utilities must answer to state public utility commissions and publicly owned utilities do not, they
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contend that dissatisfied consumers have more recourse to redress complaints under private ownership than they would under public ownership. Although this argument is not as prevalent today as it has been in the past, private ownership advocates also contended that public ownership often led to political rather than economic decisions. For example, inefficient workers may be retained by publicly owned utilities to avoid a political fight rather than be dismissed. No such inefficiencies would be tolerated in an investor-owned utility.
A NEW GOVERNANCE PARADIGM Seldom can any government organization function without interacting with and gaining the cooperation of other organizations. In the past, this interaction was sometimes coercive – compliance was dictated by law or by the power of the purse. In the long run, however, this governance model has been shown to be less effective than a collaborative approach. Organizational cooperation can be attained in several different ways: by competition, collusion, overlapping fields of operations, and dependence on the expertise available only in other organizations’ specialization (Bozeman and Straussman 1991). In the arena of public utility management and governance, only recently has this cooperative model emerged. The evolution in the way that various levels of government are approaching their operational and regulatory oversight of public utilities suggest that a major governance paradigm shift is underway in all levels of government (Agranoff and McGuire 2001). Utility managers are still struggling to find their way through this new competitive environment. For example, investor-owned utilities that still operate in the regulated environment often face a more authoritative and bureaucratic operating environment than the publicly owned utilities that are outsourcing their traditional activities to private-sector contractors. Traditionally, management of public service has operated under a topdown or donor-recipient governance model. Both of the models emphasize superior level control over subordinate’s actions. These models emphasized the enforcement of laws, regulations, standards, and guidelines. The top-down model mirrors a national governance model, in which the federal government manages its policies and programs through state and local governments. Federal laws such as the Public Utility Holding Company Act of 1935 ensured that utility operations at the customer delivery interface would always be controlled by elected or appointed state public utility commissioners. Equally, local administrators were given the responsibility to ensure
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that rules, regulations, and standards were followed. Congress passed laws which established policy; the Federal Energy Regulatory Commission, Environmental Protection Agency (EPA), and SEC interpreted the policy and set operating policies; state legislators developed specific rules from those standards; and utility commissions approved industry-suggested procedure for implementing the rules. The donor–recipient management model addressed some of the pitfalls inherent in an authoritative top-down management approach. This model presupposes the existence of a mutually dependent relationship among the various intergovernmental and private enterprise actors functioning cooperatively, but still working toward accomplishing the objectives of the superior organization. This model is exemplified in the way lower level agencies have organized their activities to comply with standards established by grant disseminating, higher-level agencies. It is an implied ‘Do it our way or no way’ model. Today, however, two new governance models seem to be replacing the traditional management approaches. These are a network model and a jurisdiction-based model. Both are more collaborative than are the top-down or donor–recipient models. Utility industry restructuring and deregulation are reflections of this major paradigm shift in utility governance. The network model is characterized by multiple, independent government and nongovernment organizations pursuing similar goals. The model is applicable in situations where a group of different participants, none of whom has the power to shape the strategies of others in the group, form a loose network to accomplish some specific goal. Under this scenario, the boundaries between public and private utility operations are often blurred. For example, the EPA and local water utilities share a common goal of providing only clean, safe drinking water to the public. The EPA has issued a large number of standards and regulations that require utilities to test for and remove toxic chemicals and other pollutants. A growing number of cities are negotiating with EPA to modify the workload and cost burden placed upon them by federal water quality rules. EPA requires even very small water utilities to regularly test for and remove a long list of toxic chemicals, minerals, and other pollutants from their drinking water. In some locations, however, it is highly unlikely that certain pollutants on the list will appear in the local water supply. These community utilities have proposed to the EPA that they develop their own water quality standards, with their own priorities for removal. EPA has approved the proposals. In sum, the network of municipal utilities and EPA has resulted in a model that is based on the assumption that ‘not everybody will comply and not everybody will defy’ (Agranoff and McGuire 2001, p. 674). It is far
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more efficient for EPA to focus their efforts on those who do not comply, simply receiving periodic reports from others in the network. Clearly, this governance approach allows far greater flexibility than the top-down and donor–recipient models. The network model is based on the interdependencies of the participating organizations, agencies, or individuals. Interdependence means that all participants will benefit in some way because of their mutual interest in some program or activity. It also implies that a problem cannot be solved unless all participants freely collaborate. Example of a Jurisdiction-Based Model The jurisdiction-based governance model is found most often in highly complex situations where significant intergovernmental and interorganizational cooperation is required. This model is seen in situations where one government jurisdiction requests and incorporates contributions of other public- and private-participant organizations. The plan developed by the initial jurisdiction includes the contributions and adjustments proposed by other jurisdictions. An example of a jurisdiction-based governance model can be seen in the utility extension plan of the rural community of Shelton, Washington. The utility department of this small city is the lead agency in a multi-jurisdictional plan to extend water and sewer service to other jurisdictions outside the city boundaries. In 1992, the City of Shelton entered into an interim intergovernmental agreement in partnership with the local Port of Shelton, the Washington State Department of Corrections and its nearby Correction Center, the State Patrol’s Training Academy, Mason County, and Public Utility District No. 1, which provides power to part of the area to be served. Other organizations such as local Native American tribes, the EPA, and state and federal fish and wildlife agencies are also tangentially involved in the outcome of the project. The agreement covers extending city sewer and water lines, enlarging the city’s sewage treatment plant, sinking new wells, and installing new water treatment facilities. The Port operates a former U.S. Navy auxiliary airport and industrial park outside the City; both the State Patrol Training Academy and State Corrections Center are also outside the City. All of the facilities lie in the State-approved Urban Development Area plan (required of all communities for controlling urban sprawl and planning for future growth). As lead agency in the $42 million plus proposal, the City of Shelton is responsible for recordkeeping and recording. The City has set up two special business funds to account for the regional project, with each fund having four ‘customers’: the City, Port, Training Academy, and Corrections Center. Environmental analyses and construction planning are being conducted by outside consulting engineers and designers. Planning sessions
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take place in the City’s new Civic Center Building, a recently remodeled former retail facility. The project is expected to be financed through a mix of grants and loans. Each of the four chief partners is to pay its proportionate share of the construction costs and normal usage rates. Construction was expected to begin in 2004 or 2005. After what was described in the local press as a series of costly delays, in early 2004 the group employed the retired county director of utilities on a six-months’ contract to monitor internal and external project progress. The contract was later extended with no definite ending. This example of a jurisdiction-based activity follows the governance model described by Agranoff and McGuire, who describe jurisdictionbased management as providing significant benefits for all project participants: Jurisdiction-based activity emphasizes local managers taking strategic action with multiple actors and agencies from various governments and sectors. . . . Bargaining and negotiations are important instruments of jurisdiction-based management. Bargaining by local managers within programs of vertical (state or federal government) or horizontal (metropolitan, regional, or intersectional) origin provide alternatives to unilateral concession, resulting in a ‘mutually beneficial solution.’ (Agranoff and McGuire 2001, p. 675)
In a classic multi-organizational agreement no one unit is deemed to be superior or subordinate to others and no central participant provides guidance or control. In the Shelton interorganizational agreement, the City has assumed the role of lead agency. Whether this was by default or by plan, the delays and cost escalation experienced clearly show the need for someone to be in charge. The Shelton agreement may thus be said to incorporate parts of both the network and jurisdictional governance models. This may be a portent of the nature of other such cooperative and collaborative utility ventures, regardless of the formal ownership or governance model of any or all of the participants.
SUMMARY The question of governance has again become an issue in public utility management. Restructuring, unbundling, deregulation, privatization, wholesale and retail competition, and outsourcing: these and other trends are having an impact on the already complex governance system that exists in this industry. Governance of public utilities in the U.S. may be the most complex of all industries. Ownership in the electricity and natural gas sectors is shared
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by two very different enterprise forms. In rural areas, utilities are more often than not owned by consumer cooperatives. In urban areas, governance takes place through state and local regulatory authorities controlling the operations of private or investor-owned utilities. IOUs serve about 75 percent of the population. Ownership of water and wastewater utilities has, until recently, generally followed a municipal or mutual society-owned model. Most private utilities are organized as corporations. In corporations, owners of common stock have the right to elect their representatives to the corporation’s board of directors. Board members are responsible for monitoring, directing, and appointing the firm’s top managers. In the early history of the industry, mergers and acquisitions brought together the many small, competing utilities into very large, connected ‘natural monopolies.’ Eventually, these consolidated monopolies grew into very large, often national, monopolies. Progressive Era reforms attempted to control these large enterprises. Government’s involvement in utility governance functions on three levels: federal, state, and local. The federal government owns and operates the nation’s largest power generating plants and conducts most investigations of private company operations and alleged fraud. It also regulates the issuance of securities, controls and issues permits to build hydroelectric facilities on navigable streams, and is responsible for the locating and construction of new nuclear power generators. State governments exercise most direct rate regulatory authority. Municipal governments still own many utility systems, mostly in the distribution segment of the industry. Few municipalities produce their own power, purchasing it from either public or private producers. They own and operate much of their water and wastewater systems, although wastewater systems are more likely to be regional in scope today. Six separate utility governance models exist today, four of which lie between the extremes of private ownership and public ownership. Between these poles are four ownership variations: (1) nonprofit trust or company, (2) public interest company, (3) consumer mutual society, and (4) public authority. Two new governance models seem to be replacing the traditional topdown or donor–recipient management approaches. These are a network model and a jurisdiction-based model. Both are more collaborative than are the top-down or donor recipient models. The network model is characterized by multiple independent governments and nongovernment organizations pursuing similar goals; it is applicable in situations where a group of different participants, none of whom has the power to shape the strategies of others in the group, form a loose network to accomplish some specific goal.
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The jurisdiction-based governance model is found most often in highly complex contexts such as those situations where significant intergovernmental and interorganizational cooperation is required. This model is seen in situations where one government jurisdiction requests and incorporates contributions of other public and private participant organizations.
ADDITIONAL READING Bruchley, Stuart (1990), Enterprise: The Dynamic Economy of a Free People, Cambridge, MA: Harvard University Press. Hampton, Howard (2003), Public Power: The Fight for Publicly Owned Electricity, Toronto: Insomniac Press. Kettl, Donald F. (2002), The Transformation of Governance, Baltimore, MD: Johns Hopkins University Press.
PART III
Public utility system challenges In addition to the broad management challenges that face all managers in the public utility industry, each segment of the industry has its own particular challenges. This section introduces readers to some of the more pressing challenges in the electricity, natural gas, water and wastewater utilities. In every utility, managers are concerned foremost with maintaining the security of their operations – particularly in light of the devastating terrorist attacks of September 11, 2001. Beyond system security, managers are next concerned with ensuring that they have sufficient capacity to meet the growing demands of a changing market. Part of this problem is coming up with the money needed to replace aging infrastructure and upgrade systems to meet new environmental controls, while also finding the funds to build the new capacity to meet the needs of a growing population.
13.
Challenges in the electric energy industry
A few minutes after 4:00 p.m., Eastern Daylight Time, on the afternoon of August 14, 2003, an enormous electricity blackout hit much of the Eastern United States and Canada. Something like 50 million people were suddenly and completely without electric power. In little more than half an hour, nearly 62 000 megawatts of electricity had fallen off-line. Affected were the Canadian Province of Ontario and the states of Connecticut, Massachusetts, Michigan, New Jersey, New York, Ohio, Pennsylvania, and Vermont. In some areas, the power was out for two full days; parts of Ontario suffered rolling blackouts for more than a week before full restoration of power (McCann 2004). An investigation under the direction of a joint U.S. and Canadian task force reported that the power outage was probably caused initially by the failure of the Ohio grid operator to adequately control tree growth in its transmission rights-of-way. This was cited as the cause of an outage of three local transmission lines over 36 minutes beginning at 3:05 p.m. EDT. This caused congestion overloads on other parts of the grid. In addition, the grid regulators failed to diagnose the problem in time to avoid the loss at 4:06 p.m. of an overloaded major transmission line. Loss of this line, in turn, resulted in loads that were too heavy being placed on other lines. To avoid permanent damage to the grid and related equipment, automatic shutdowns fell into place across the entire interconnected grid. By 4:13 p.m., the blackout was complete. Why the blackout occurred is as much a result of the fundamental nature of electricity as it is any other reason. The most important feature is known as loop flow. Loop flow means that electricity takes all available routes to get from one point to another; the flow of electricity across a transmission network cannot always be economically directed along a particular line. When one line is shut down for any reason, as occurred in Ohio in 2003, electric continues to flow across all available transmission lines. This can cause overloads on the other lines, which are themselves then shut down to avoid damage to the system. Moreover, loop flow means that the use of the transmission grid by any one generator or power customer has an effect on the amount of transmission capacity available to all users. This is why the 219
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Federal Energy Regulatory Commission requires that transmission systems be constantly monitored. Monitoring is particularly important when all parts of the system are congested. This occurs on hot summer afternoons when air conditioning demand is high. This is what happened on that hot August afternoon. Another particularity of electricity is that it cannot be economically stored. Power must be used as it is produced, and produced as it is used. However, the capacity of all transmission lines in the national grid has an absolute upper limit. The transmission grid must have sufficient capacity to move the generated electricity to load or demand centers. Insufficient capacity results in line overloads. When overloads happen, automatic safeguards shut down generators. Personnel charged with monitoring the grid must ensure that the system is always balanced within a narrow band of tolerances.
THE CHANGING POWER INDUSTRY The electric power industry is in the midst of radical change. Historically, regulated investor-owned utilities served specified markets under exclusive franchise. State regulators monitored operations and regulated rates, approving only the rates that they believed were the lowest possible prices for consumers while still granting the utilities a ‘fair’ rate of return on their investment. The service areas of regulated utilities were usually restricted to either (1) a single region within a given state, (2) more than one region but in contiguous areas outside the state, or (3) both. The vertically integrated utilities, in turn, were required to provide electric services to any and all customers in their areas of operation and to maintain extra capacity ready to bring online at any moment it was needed. For many years, this system worked well. However, the fuel price shocks and shortages that occurred during the 1970s ushered in changes that are still going on today. The monopolistic, tightly regulated utilities that were created by legislation enacted during the 1930s to control utility holding company excesses are becoming increasingly exposed to intense competition, much of which is global in origin. This is particularly true in the generating and wholesale power sale sectors of the electricity industry. Similar competitive pressures are affecting many privately held natural gas and water utilities. Even greater changes were brought about by the National Energy Policy Act (NEPA) of 1992. Passage of this bill brought deregulation and restructuring of the industry to front stage. Box 13.1 illustrates how these forces changed one formerly vertically integrated utility in the State of Texas (McCann 2004).
Electric energy
BOX 13.1
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HOW RESTRUCTURING BROUGHT CHANGES TO ONE INTEGRATED UTILITY
CenterPoint Energy of Houston, Texas, saw its historic method of serving customers come to an end in January of 2002. CenterPoint had been an integrated utility for more than 120 years. Now, it would be separated into three parts: delivery, retail, and power generation. CenterPoint Energy became the firm that delivered power from electric generators to the homes and businesses in its service area. Future operations would focus on the construction, maintenance, and repair of the transmission, substation, distribution, and street light systems. Under deregulation, CenterPoint would no longer sell electricity or send bills to residential, commercial, or industrial customers. Retail operations of invoicing, payments processing, and credit were from then on handled by competitive retail companies. Customers could choose the retail provider they wanted, but CenterPoint remained responsible for seeing that the electricity was delivered to the customer. Instead of billing every individual customer, CenterPoint would now bill only the retail providers for these services. Source:
CenterPoint Energy, 2002 Annual Report.
The shocks that occurred in the nonregulated power marketing and trading field during 2000 and 2001 in California have resulted in cessation of the move toward deregulation; no state has initiated a deregulation program since 2000 (Joskow 2003). Some industry analysts expect that, over the long term, there will be a revival of competitive activity. The industry analysts also believe that deregulation of the industry will result in the power generation segment becoming increasingly consolidated, with only a few very-large international firms in control of most of the market. They added that, even though electricity buyers will still be able to choose from whom they will buy bulk power, this consolidation could very likely result in a market environment that is much less competitive than government regulators initially intended (McCann 2004). According to the federal Energy Information Administration (EIA), as of December, 2003, restructuring was alive in the United States; 18 of the 24 states that had announced plans to restructure the electricity in their
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jurisdictions reported they were continuing to do so, despite the problems experienced by California and the District of Columbia. In the 24 states that had originally announced restructuring plans, legislatures had either enacted enabling legislation or issued a regulatory order to implement retail access (retail access means that customers will be able to select which firm provides power to their home or business). Retail competition was available to some or all customers, or soon would be, in all of the 18 except Oregon. Oregon state law allowed nonresidential customers access, but no customers were yet participating in the retail access program. California was the only state in which retail access to competitive suppliers was completely suspended.
COMPONENTS OF THE POWER INDUSTRY The electric power industry is made up of a number of different participants. At the most basic level, these can be grouped into two broad categories: buyers and sellers. Buyers of power are divided into three classes: residential (single family residences and individually metered apartment units), commercial, and industrial. On the seller side are five main types of organizations: investor-owned utilities, publicly owned utilities, rural electric cooperatives, federally owned utilities, and independent power producers (also known as nonutility generators). In 2003, investor-owned utilities controlled 71 percent of the U.S. generating capacity and were responsible for 74 percent of all retail sales of electricity. Publicly owned utilities accounted for about 14 percent of U.S. generating capacity and 15 percent of electricity sales. They include municipal utilities, public power districts, irrigation districts, and state authorities. Rural electric cooperatives consist of distribution systems cooperatively owned by rural farmers and communities that primarily distribute power to residential customers. Rural cooperatives also provide power for irrigation pumping. Cooperatives have the lowest generating capacity of all providers. Federally owned utilities consist of five federal wholesale power producers and four federal power-marketing administrations. Most of these agencies market their power through one of four administrations, the largest of which is the Bonneville Power Administration. The exception is the Tennessee Valley Authority (TVA), which markets its own electricity. The TVA is the largest federally owned producer of electricity. Finally, independent power producers include more than 2000 generators not owned or operated directly by a utility within a designated franchise service area. However, they may be owned by a utility holding company
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affiliate. Collectively, they account for about 19 percent of U.S. generating capacity. Regardless of their system of governance or where on the globe they are located, electric power systems consist of four major functional components: (1) power generation, (2) transmission of high voltage power from where it is generated to where it is needed, (3) distribution of low voltage power to various types of customers, and (4) a marketing function. Marketing includes such ancillary services as retail marketing, connection and disconnection, meter reading, repair and upgrading, billing, and increasingly, conservation programs and trading in derivatives.
POWER GENERATION CHALLENGES Electric power is generated by revolving a magnet within a coil of copper wire. A variety of technologies and fuels are used to turn the magnets, including falling water, wind power, heat from beneath the surface of the earth (geothermal), and steam and gas turbines powered by fossil fuels and nuclear reactors. Table 13.1 displays the distribution of fuels used to generate power in the U.S. in 2002 and the percentage distribution that is expected in 2010. Coal-fired steam turbine plants generated over half of all the investor-owned electricity in the United States; this percentage is expected to become even greater in the decade ahead. Coal is followed Table 13.1 Fuels used to generate electricity in the U.S. in 2002 and 2010 projections
Fuel sources Coal Natural gas Nuclear power Renewable sources (hydroelectric, solar, geothermal, wind, etc.) Petroleum Other (hydrogen, sulfur, other miscellaneous) Totals Source:
2002 (%)
2010 (%)
50.2 17.9 20.3
51.9 20.9 17.3
9.1 2.3
9.2 0.7
2.0
1.0
100.0
100.0
Standard & Poor’s Industry Surveys: Industry Profile, 2004.
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by natural gas and nuclear generation, each with close to 20 percent of the total. According to Brennan et al. (2002), the average coal-fired steam turbine has a capacity of roughly 250 megawatts, which is roughly the amount of power needed to supply a town of 60 000 homes. As a rule, coal-fired plants which contain multiple steam turbines require a capacity of 300–600 megawatts to produce at an output that roughly minimizes the average cost of producing a kilowatt-hour. Construction costs at the beginning of the twenty-first century were about $1100 a kilowatt. Operating costs ranged from less than 2 cents to a little more than 3 cents per kilowatt hour, depending upon the age of the plant and the types of environmental controls it is required to have. In 2002, natural gas was the second most popular choice of fuel to power electric generators. Two technologies use natural gas: standard gas turbines (similar to those found on jet aircraft) and combined-cycle gas turbines. In gas turbines, hot gasses from the combustion of natural gas (or fuel oil) pass directly through the turbines that spin the electric generator. These account for roughly 10 percent of total generating capacity. Gas turbines are often used to meet peak demands. They have relatively low capital costs, but high operating costs. The average generating capacity is 35 megawatts. New gas turbines have a construction cost of roughly $260 per kilowatt and operating costs that are 30 to 50 percent higher than a typical coal plant. The second type is the combined-cycle gas turbine, or CCGT system. CCGT generators use both combustion turbine and steam turbine technologies. The hot gases drive a turbine in the same way that gas turbine generators function. However, the heat from CCGT systems is not dissipated immediately. Rather, it is collected and used to create steam that is then used to drive a steam turbine in the same system. About two-thirds of the power in a CCGT system is generated by the gas turbine, and one-third is generated by the steam turbine. CCGT systems are compact, reliable, and versatile; they also require short installation times. The energy efficiency or the amount of electricity produced per unit of fuel for a CCGT can be as much as 70 percent greater than a typical coal plant and 40 percent higher than a gas turbine plant. CCGT plants now produce about 8 percent of all electricity. According to Brennan et al. (2002), new CCGT plants can be constructed for about $450 per kilowatt, and they also have low pollution emissions. Continuing Decline Nuclear plants now generate about 20 percent of the nation’s electricity. This percentage is expected to drop to something like 17 percent by 2010,
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although high natural gas prices and rising prices of coal may change this prediction. Coal has been cheap and readily available. As a result, it has been the fuel of choice for most very large power generating plants. Predictions are for coal prices to remain more or less stable over the next decade, although its popularity, together with rapid increases in other fuels, may result in the price of coal to increase more than expected. Nuclear fission creates heat to produce steam, which is then used to turn the power plant turbines in much the same way as steam generated from coal, gas, or oil burning generating systems. No new nuclear plants have been constructed since 1979; they are among the most expensive plants to build, and they have high maintenance costs. However, the cost of operating the plants is quite low, something in the neighborhood of 1 to 2 cents per kWh. Fossil fuels are also used to power internal combustion generators. The systems burn either diesel fuel or natural gas much like power is created in a diesel electric locomotive. The internal combustion engine drives a generator (similar to an automobile alternator). These systems are compact and able to start up and shut down almost instantaneously. As a result, they are often used primarily for generating power for short periods when peak demand exceeds normal generating capacity. They range from 1 to 3 megawatts in size. They generate only a very small fraction of power in the United States or Canada. Renewable resources constitute little more than 9 percent of the power generated in the United States. Of these fuels, by far the most important is hydroelectric power. About 8 percent of U.S. electricity comes from hydropower. Most hydroelectric generators are located in the West and Northwestern sections of the country. Two types of hydropower dominate this sector of the industry: falling water stored behind dams, and rivercurrent driven generators (called run-of-river generators). A third system is pumped storage, in which falling water is used in lowdemand periods to power pumps that lift the water back to storage areas above the generators. The water is then reused to generate power to meet peak demand requirements. The fuel costs for these types of hydroelectric generators are zero, but construction costs are high. Other, nonhydroelectric renewables include wind, solar, geothermal, and biomass combustion. Together, these technologies produce a little more than 1 percent or less of the nation’s electricity. The Role of Distributed Generation One of the fastest growing parts of the generation industry is the distributed generation or distributed energy segment. Distributed generation is defined as small generators that are located near or at the consumer site,
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System challenges
but which stay within the control of the distribution utility. These small generators are usually not connected to the transmission grid, but supply power directly to the customer. They are typically used to supplement power from the grid during peak demand periods, when prices tend to escalate rapidly. According to the Energy Information Administration, technological advances have improved the economics of small generators. Fuel cells and photovoltaic systems are also becoming available as alternative sources. Until the recent rapid increases in the price of natural gas, distributed generation was seen as a viable alternative to mandated reductions in power use or constructing new large central generating plants. Locating a number of small, very efficient and cost-effective natural gas powered jetengine turbines were seen as the alternative to building new, large, fossilfuel-powered steam generators. The economics have forced utilities to take another look at this alternative, however. A number of utilities are considering adding new coal-fired or nuclear powered plants over the next decade or so.
POWER TRANSMISSION CHALLENGES Transmission is the movement of electric power over relatively large distances from where the power is generated to where the power is put to use. An interconnected network of transmission lines is referred to as a transmission ‘grid’ (ERA 2000). Transmission grids consist of interconnected high voltage overhead and underground lines made of copper or aluminum. The power is stepped up to a higher voltage at the site of its generation. It is then transmitted, sometimes over very long distances. Transformers at substations then step down the high voltage power to the low voltage needed by distribution lines in major load centers. Load centers are concentrations of residential, commercial, industrial power users, or all three. Box 13.2 describes a cross-border interconnect arrangement between El Paso Electric and its bordering state in Mexico. In the U.S., investor-owned utilities own nearly three-fourths of existing transmission lines; federal utilities own 13 percent, and public utilities and cooperatives own 14 percent. Not all utilities own transmission lines; nor are transmission lines owned by any independent power producers or power marketers (EIA 2000). This picture is changing, however, as the FERC continues to push for more wholesale competition and efficiency in the transmission sector. Two interconnected transmission grids or interties (the connections between large, regional power systems, or grids) have been formed to ensure
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efficient transmission of power across all of North America: the Eastern Interconnected System, which serves the majority of the Central and Eastern U.S. and parts of Canada; the Western Interconnected Grid, which serves the west side of the Rocky Mountain area, part of Texas, and parts of Western Canada and Mexico. A much smaller grid, the Texas Interconnected System, serves the part of the State of Texas that is not a part of the Western Interconnected Grid. The Texas grid is also partially connected to the other two North American grids. Both the Western and Texas interconnects are linked with Mexico; the Eastern and Western interconnects are completely integrated with most of Canada. Interconnected utilities in the grids coordinate their operations and buy and sell power to each other.
BOX 13.2
CROSS-BORDER INTERCONNECT BY A TEXAS UTILITY
El Paso Electric (EPE), an investor-owned public utility engaged in the generation, transmission, and distribution of electricity in West Texas and southern New Mexico, has had a long and mutually beneficial relationship with Mexico’s Comisión Federal de Electricidad (CFE). El Paso Electric has negotiated a contract to sell up to 150 megawatts of power per hour during the summer months. The sales improved the company’s earnings during 2002 by about 3 cents per share. The relationship between El Paso Electric and its Mexican neighbors goes beyond just selling power. For example, in 2002, EPE and city officials in Juarez, Mexico, just across the river from El Paso, received approval from the Texas Commission on Environmental Quality on a joint proposal to improve air quality in the region. EPE is replacing older, high-polluting brick kilns in Juarez with new, cleaner kilns developed by a former professor at New Mexico State University. Emissions from each new kiln are about 80 percent lower than the kilns they replace. EPE receives emission credits from Texas. Gary R. Hedrick, EPE’s president and CEO, said about the relationship, ‘EPE looks forward to continuing its partnership with the Republic of Mexico on other binational issues that affect the border region.’ Source:
Shareholder Statement, EPE 2002 Annual Report.
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Control of the National Grid The FERC maintains oversight control over the three extra-high voltage grids. Within these three electric grids are about 150 control areas, most of which are operated by the dominant investor-owned utility in the region (Brennan et al. 2002). These are electric geographic areas with control operators that balance electric load while maintaining reliability. Most of these control areas are in the Eastern Interconnection; only 12 are in the Texas Interconnection. Control Area Operators (CAOs) dispatch power from a central control center to balance supply and demand and maintain system safety and reliability. Nine North American Electric Reliability Council regions and an affiliate have been formed within the three major national grids. The Reliability Council is a voluntary, nonprofit corporation formed by members from all segments of the industry, including utilities, power producers, power marketers, and power customers. The Reliability Council was formed in 1968 after the catastrophic Northeast blackout. Individual councils are responsible for the coordination of bulk power policies that affect reliability and adequacy of service in their regions. They also share operating and planning information. The ten area councils are: ● ● ● ● ● ● ● ● ● ●
ECAR: ERCOT: FRCC: MAAC: MAIN: MAPP: NPCC: SERC: SPP: WSCC:
East Central Area Reliability Coordination Agreement Electric Reliability Council of Texas Florida Reliability Coordinating Council Mid-Atlantic Area Council Mid-America Interconnected Network Mid-Continent Area Power Pool Northeast Power Coordinating Council Southeastern Electric Reliability Council Southwest Power Pool Western Systems Coordinating Council
The boundaries of these NERC regions follow the service areas of the utilities in the region and, as a result, do not exactly follow state boundaries. The grid is also tied in with grids in Canada and Mexico, making the system a truly international network of electric power. Changes in the Transmission Grid System Prior to the late 1990s, most electric power was supplied to customers by vertically integrated public utilities. About 75 percent of these utilities were investor owned; the remaining 25 percent were publicly owned.
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Municipally owned utilities served customers in urban areas; organizations operating as special districts served rural areas (Public Utility Districts, for example). The large investor-owned utilities tended to be vertically integrated. They owned and operated power generating plants, transmission lines, local distribution systems, and did their own meter reading, billing, and other ancillary service activities. Beginning with passage of the Public Utility Regulatory Policies Act (PURPA) of 1978, transmission owners were required to allow open access to their lines by alternative energy producers, including small dams, solar, and biomass generators. To encourage their growth, these small generators were exempt from state regulation. The National Energy Policy Act of 1992 carried open access a step farther. The vertically integrated utilities were to be ‘unbundled’ under a plan designed to replace utility monopolies with competition. Unbundling meant separating the functions of generation, transmission, and distribution. These were to function as separate competitive businesses. The first plan was to establish competition at the wholesale level. The FERC issued two Orders in 1996 that further enabled open access: Order 888, which required open-access transmission; and Order 889, which required establishment of electronic systems to share information about transmission capacity. Order 888 had two goals: (1) elimination of anticompetitive practices by transmission line owners, including elimination of owner discrimination in granting access to the grid by requiring a universally applied open access transmission tariff; and (2) to enable the utilities that constructed the lines to recover what were called their stranded costs (also called sunk costs, or transition costs). ‘Transition costs’ are expenses it costs the utility to transition from a vertically integrated, full service utility; ‘sunk costs’ are the sums expended by the utility in years past to develop and install such infrastructures as dams, transmission lines, and local distribution facilities. Utilities have almost always borrowed or sold bonds to pay the cost of infrastructure as it was installed. Utilities repay these loans over periods of 20, 30 or more years. Traditionally, utilities were allowed to pass on these repayment costs to their customers. Some critics of the public utility system have called for this ‘pass-through’ to stop once the property is divested. According to the EIA (2002, p. 64), ‘The rationale for allowing stranded cost recovery is that utilities have invested billions of dollars in facilities under a regulatory regime that allowed cost recovery of all prudent investments.’ FERC endorsed the idea in the belief that recover of sunk costs was needed if the move toward competition was going to succeed. At the same time, they recognized that recovery of sunk costs would delay lower prices that were expected to accrue from competition.
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Order 888 required owners of transmission lines to separate the lines from their other business, a practice called ‘unbundling.’ This meant that transmission owners were required to use transmission service on lines they owned under the same tariff and access conditions as other transmission users – in what was called a ‘comparability standard.’ Order 889 was issued in order to make the pricing and access process more transparent. All investor-owned utilities were required to participate in an Open Access Same-time Information System (OASIS). This interactive Internet-based database contains information on the availability of transmission capacity, capacity reserved for one or more users, other services, and transmission prices. As of 2003, 166 transmission line owners participated by providing information about the transmission facilities. Order 2000 issued in 1999 encouraged all public and investor-owned electric utilities to place their transmission systems under the independent control of a regional transmission organization or RTO. Implementing the RTO concept has been described as, ‘Arguably FERC’s most significant and, to some extent, most tumultuous activity undertaken in its effort to create a more competitive and efficient industry’ (Energy Information Administration 2002, p. 66). Compliance with the RTO order has been slow; most of the national transmission grid is still not under control of an independent RTO. In consequence, in July 2002 the FERC proposed its ‘standard market design’ (SMD) rule. This would have established a single set of rules for the entire North American wholesale market. The SMD proposal was revised in April of 2003 to allow for regional opposition and renamed ‘the wholesale power market platform.’ The revised SMD proposal was part of the federal energy bill of 2003, which Congress failed to pass. The energy bill called for a delay of three years before the FERC could require utilities to join a regional transmission organization or before it could mandate a standard market design. The 2003 bill would also have made grid reliability standards mandatory and would have required federal permits for transmission lines. A key section of the failed bill would have repealed the Public Utility Holding Company Act of 1935. McCann (2004) described the FERC’s order for a standard market design as one of the most far-reaching of its proposals governing the transmission of wholesale electric power. The standard markets would have established and monitored a set of consistent transmission rules applicable to all participants. The FERC was convinced that the lack of a clear set of rules governing the wholesale electric industry was responsible for failure of a truly competitive power market to emerge in North America.
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The FERC’s SMD concept was strongly opposed by state regulators and utilities in the U.S. Northwest and Southeast. Opponents of the concept believed that the SMD plan might work for the changing transmission markets in the Northeast, but it was not right for their own areas. For example, the service territories of the Northwest are much larger than those in the East. There are relatively few but very long transmission lines in the West. State regulators and market participants did not believe there was a need for new lines for trading by power marketers. Also, the Northwest depends heavily on publicly owned hydroelectric power, which usually is not open to competitive market pricing. In the Southeast, on the other hand, there was great concern that the imposition of the SMD would result in those regions losing their low-cost advantage, as nationwide trading could possibly force an increase in power prices in that region. Loss of that advantage would, it was felt, limit their ability to attract new industries to the region, thus severely curtailing economic development.
CHALLENGES IN THE DISTRIBUTION SECTOR Distribution is the process of moving electricity from the high-voltage transmission grid to lower voltages and delivering it to customers’meters. This aspect of the industry is still considered to be a ‘natural monopoly’ and, as such, remains under the control of state Public Utility Commissions (PUCs). Distribution is considered to be an intrastate function, even when power suppliers serve customers in more than one state. The process of providing the electric energy to ultimate customers is called retail marketing or retail sale. Investor-owned utilities that provide power distribution services are to remain the regulated portion of the utility industry, serving residential, commercial, and industrial customers, sometimes in competition with non-regulated firms. Under the regulated system, state PUCs approve retail rates for electricity based on the cost of service plus an allowed ‘fair’ rate of return. Utilities present information at rate hearings when seeking approval for a proposed rate change. The total cost of service includes the cost of generated and purchased power, the capital cost of the utility’s generating plants called stranded costs. ‘Stranded costs’ are sunk costs that the utility may or may not be able to recover after restructuring (forced sale) or donation to nonprofit operators. They contend they made the investments in good faith to meet all required demand. Utilities have complained that not allowing recovery of their investments is unfair; the issue was not resolved as of January 2005.). The cost of transmission, installed distribution infrastructure, all operations and maintenance, as well as the cost of programs
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required by the PUC to maintain consumer safety, energy efficiency, and environmental protection are all allowable costs they believe should be included in rate determinations. In addition, federal, state, and local taxes are generally included in the rate base. The major challenge facing utility distribution companies may be learning how to effectively and efficiently operate their businesses under conditions of competition rather than as regulated monopolies. In the few states that have adopted retail competition, some commercial and large industrial power users have taken the opportunity to choose from among two or more competing suppliers for the power delivered to their premises. However, very few residential customers have opted to change electricity suppliers. Residential retail competition is not moving forward as quickly as federal regulators had hoped.
CHALLENGES OF RESTRUCTURING THE INDUSTRY Events taking place in the industry have been described by the industry trade association, the Edison Electric Institute, as among the most important that the industry has ever faced. The most important of these changes may be the restructuring of the industry underway in many parts of the world. The industry is being forced to shift from being one of the most highly regulated of all industries to one in which aggressive competition is reshaping the power generation and retail sale to customers segments (Edison Electric Institute 2004). Opponents of restructuring in the industry see it in a different light. Australian professor and privatization critic Sharon Beder provided this version of the process in her book Power Play: The Fight to Control the World’s Electricity: The term ‘deregulation,’ when referring to electricity is essentially a misnomer, since the changes involved are not really about getting rid of regulations: they are about replacing the regulations that protect the public and the environment with rules to ensure the smooth running of the market and the electricity system. ‘Privatisation’ is the more accurate term, because what is happening in the case of deregulation is the privatisation of control over electricity provision. The use of the term is endorsed by the US Department of Energy (DOE), which says: ‘We treat privatization . . . as any movement that diminishes public ownership and control and increases private ownership and control. (Beder 2003, p. 2)
The drive toward restructuring the electric power industry began in 1978 with passage of the Public Utility Regulatory Policies Act (PURPA). This was passed in response to the unstable energy climate of the 1970s; it was
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triggered by the actions of the OPEC cartel, when OPEC quadrupled the price of a barrel of petroleum on the open market. PURPA encouraged conservation of electrical energy. More importantly, it created a new class of organizations in the energy supply chain: nonutility generators. Established utilities were required to buy power from these small independent power producers and qualified cogenerators. PURPA also gave the Federal Energy Regulatory Agency the authority to require owners of transmission lines to pass power generated by independents over the privately owned lines. As a result of the 2000–01 energy crisis that began in California and included the collapse of the energy trading company Enron, the move toward restructuring has lost its momentum. When Congress failed to pass the energy bill, it left many questions still unresolved, including the following restructuring issues (EIA 2000): ● ● ● ● ● ●
● ●
● ● ● ● ● ●
●
● ●
Mandatory participation in a regional transmission organization; Bulk power reliability; Nuclear decommissioning provisions; Transmission grid expansion and construction; Reform of TVA and federal power marketing administrations; Federal authority to regulate retail sales, protect retail consumers, and regulate local grid interconnections; Utility mergers; Public benefits fund (funds set aside to provide non-utility benefits to local consumers); Retail net metering; Emissions caps and standards for generators; IRS restrictions on ‘private use’ of municipal electric systems; State/federal jurisdiction clarification; Retail sales to federal agencies; Retail reciprocity (two or more competitors assisting each other by providing local customers’ power); Extension of Order 888 wholesaling wheeling rules to transmission by municipals, cooperatives, federal power marketing administrations, and TVA (federal government rules regarding shipping power over others’ transmission lines); Renewable energy source portfolio standards; Repeal of PUHCA and Section 210 of PURPA.
A Final Word The electric power industry is in the midst of a complete overhaul. The changes taking place are having the greatest impact upon investor-owned
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utilities. Deregulation, restructuring, and competition have forced these utilities to make drastic shifts in their strategic direction. Restructuring has brought on unbundling of the industry. Former vertically integrated utilities have had to divest themselves of major components. The biggest change has been the selling off of generating plant. Most of this generation capacity has been acquired by independent power producers. The FERC is also trying to have the utilities place their transmission assets into nonprofit regional organizations designed to control all transmission within a given market area. Finally, in those states where retail competition is allowed, some utilities have spun off their marketing units as separate, non-regulated meter-reading and billing businesses. Despite these major changes, vertical integration remains a viable strategy. A spate of mergers has produced some very large, vertically integrated regional utilities. One result of the upsurge in mergers and acquisitions has been a concentration in the ownership of power generation among a small number of firms; the 20 largest investor-owned utilities now own about 72 percent of total generation capacity (EIA 2000). The consolidation taking place in the industry has also seen some electric utilities merging with natural gas production and pipeline companies to form vertically integrated energy companies, which may be the predominant form of the industry in the future.
SUMMARY The electric power industry is undergoing radical change. Historically, regulated investor-owned utilities served specified markets under exclusive franchises. State regulators monitored operations and regulated rates, approving only the rates that they believed were the lowest possible prices for consumers while still granting the utilities a ‘fair’ rate of return on their investment. For many years, this system worked well. However, the fuel price shocks and shortages that occurred during the 1970s ushered in changes that are still going on today. The monopolistic, tightly regulated utilities created under New Deal trust-busting legislation more than 60 years ago are becoming increasingly exposed to competition, particularly in the generation and wholesale power markets. Even greater changes were brought about by the National Energy Policy Act of 1992. Passage of this bill brought deregulation and restructuring of the industry to front stage. The shocks that occurred in the nonregulated power marketing and trading field during 2000 and 2001 in California brought deregulation to an abrupt halt; no state has initiated a deregulation program since 2000,
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although there is some evidence that some states are taking another look at the concept. Electric power systems have four major functional components: (1) power generation, (2) transmission of high voltage power from where it is generated to where it is needed, (3) distribution of low voltage power to various types of customers, and (4) a marketing function. A variety of technologies and fuels are used to generate electricity, including falling water, wind power, heat from beneath the surface of the earth (geothermal), and steam and gas turbines powered by fossil fuels (coal, natural gas and petroleum), and nuclear reactors. Coal-fired steam turbine plants generated over half of all the investor-owned electricity in the United States. Coal is followed by natural gas and nuclear generation, each with close to 20 percent of the total. Transmission is the movement of electric power over relatively large distances. An interconnected network of transmission lines is referred to as a transmission grid. Transmission grids consist of interconnected high voltage overhead and underground lines of copper or aluminum. The power is stepped up to a higher voltage at the site of its generation. It is then transmitted, sometimes over very long distances. Transformers at substations then step down the high voltage power to the low voltage needed by distribution lines in major load centers. Three major transmission grids or interties have been formed to ensure efficient transmission of power across all of North America: the Eastern Interconnected System, the Western Interconnected Grid, and the Texas Interconnected System. There are about 150 control areas within the three interties to balance electric load and maintain reliability; most of the control areas are operated by the dominant investor-owned utility in the region. Nine North American Electric Reliability Council regions and an affiliate have been formed within the three major national grids. The Reliability Council is a voluntary, nonprofit corporation formed by members from all segments of the industry, including utilities, power producers, power marketers, and power customers. Beginning with passage of the Public Utility Regulatory Policies Act of 1978, transmission owners were required to allow open access to their lines by alternative energy producers, including small dams, solar, and biomass generators. The National Energy Policy Act of 1992, carried open access a step farther. The vertically integrated utilities were to be ‘unbundled’ under a plan designed to replace utility monopolies with competition. In 1996, the FERC issued Order 888, requiring open-access transmission; and Order 889, which required establishment of electronic systems to share information about transmission capacity. Order 888 had two goals: (1) elimination of anti-competitive practices by transmission line owners,
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including forbidding line owner discrimination by requiring a universally applied open access transmission tariff; and (2) to enable the utilities that constructed the lines to recover what were called their stranded costs (also called sunk costs, or transition costs). Order 2000 issued in 1999 encouraged all public and investor-owned electric utilities to place their transmission systems under the independent control of a regional transmission organization or RTO. The changes taking place in the electric power industry are having the greatest impact upon investor-owned utilities. Deregulation, restructuring, and competition have forced these utilities to make drastic shifts in their strategic direction. Restructuring has brought on unbundling of the industry. Former vertically integrated utilities have had to divest themselves of major components. The biggest change has been the selling off of generating plant. Most of this generation capacity has been acquired by independent power producers. Finally, in those states where retail competition is allowed, some utilities have spun off their marketing units as separate, non-regulated meterreading and billing businesses. The consolidation taking place in the industry has also seen some electric utilities merging with natural gas production and pipeline companies to form vertically integrated energy companies, which may become the predominant form of the industry in the future.
ADDITIONAL READING Brennan, Timothy J., Karen L. Palmer and Salvador A. Martinez (2002), Alternating Currents: Electricity Markets and Public Policy, Washington, DC: Resources for the Future. Brown, Matthew H. and Richard P. Sedano (2003), A Comprehensive View of U.S. Electric Restructuring with Policy Options for the Future, Washington DC: National Council on Electricity Policy. (http://www.ncouncil.org/restrict.pdf) Energy Information Administration (2000), The Changing Structure of the Electric Power Industry 2000: An Update, (October), Washington, DC: U.S. Department of Energy, Office of Coal, Nuclear, Electric and Alternate Fuels, No. DOE/EIA0562(00). Joskow, Paul L. (2003), The Difficult Transition to Competitive Electricity Markets in the U.S., paper prepared for the Electricity Deregulation: Where From Here?, conference at Texas A&M University, 4 April, Washington, DC: AIE-Brookings Joint Center for Regulatory Studies, http://www.aei-brooking.org/admin/authirpdfs/ page.php?id⫽271
14.
Challenges in the natural gas industry
Unlike the electric power industry, the natural gas industry has largely worked its way through the minefield of structural and environmental changes that have rocked the energy industry since the middle and late 1990s. The impact of these structural changes – deregulation, restructuring, and introduction of wholesale and retail competition – have been absorbed into the industry, resulting in what has been described as a far more efficient system than existed before. Restructuring – also called ‘retail unbundling’ – is separating the services necessary to supply gas to consumers into various components that can then be separately purchased. Since restructuring began in earnest in 1996, gas distributors and customers have benefited from lower transportation charges, greater and more reliable supplies, and – until recently – generally lower final prices (MacAvoy 2000; MarinerVolpe 2004; Shere 2004). Partially as a result of federally imposed pollution controls, demand for natural gas to fuel electricity generators and industrial processes has expanded significantly. Even as demand for natural gas has grown, the maturing of traditional North American production fields in Oklahoma, Texas, and the shallow Gulf Coast has reduced domestic supply (‘Shallow Gulf Coast fields’ is a natural gas industry term that refers specifically to offshore gas and oil fields that are close to shore rather than in deeper water in the Gulf of Mexico). Together, this tightly balanced supply and demand situation has caused natural gas prices to rise to nearly record highs and to become more volatile than they have ever been. Moreover, many of the companies that made significant investments in unregulated activities were badly burned by the 2001 and 2002 collapse of a number of energy merchant companies, led by the experiences of Enron. Many large holding companies have eliminated or severely curtailed their energy merchant operations. As a result of the industry nosedive, regulatory bodies forced energy companies to increase their equity positions. This, in turn, has slowed the pace of new investment, while increasing the number of consolidations in the industry. This, then, is the environment in which the natural gas industry finds itself during the early years of the new century. To begin to understand the nature of these 237
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challenges, it is first necessary to know the nature and history of the natural gas industry.
NATURE OF THE GAS INDUSTRY Activities of the natural gas industry is divided into three categories: upstream, midstream, and downstream activities. Upstream activities are ones performed by exploration and production and drilling companies. These are the organizations that drill for gas and pump it out of the ground. Midstream activities include the gathering of gas, processing it into its component hydrocarbons – mostly butane, propane, ethane, and methane (which makes up the bulk of the gas distributed to end customers) – and storing it for later transmission or other use. The wholesale transmission of natural gas along interstate pipelines is also generally considered a midstream function. Downstream activities include the transportation of natural gas to end users by gas utilities, which are called local distribution companies (LDCs) in the industry. LDCs may be owned either by equity shareholders or by a local government such as a city, county, or special utility district. Distribution companies purchase, transport, distribute, and resell natural gas to end users, including residential, commercial, industrial, and, increasingly, companies that use gas as a fuel for generating electricity. As in the electric power industry, a holding company parent often owns a number of LDCs that supply gas to customers in different markets. Holding companies may also own electric utility service firms, and/or unregulated energy merchants. Holding companies are usually not liable for the debts of their wholly owned distribution utilities. Rather, they are usually required by federal and state regulating agencies to segregate their diverse assets so as to protect the creditworthiness of their regulated distribution utilities. As of the end of 2003, the ten largest LDCs in North America served almost 28.3 million natural gas customers. Natural gas holding companies are subject to the same federal regulation as electric power holding companies. The primary legislation controlling holding companies is the Public Utility Holding Company Act of 1935, which was discussed earlier in the text. The Federal Energy Regulatory Commission (FERC) exercises control over all interstate aspects of the natural gas industry. Box 14.1 describes a typical large holding company, CenterPoint Energy of Houston, Texas. CenterPoint’s restructuring activity was also noted in Box 13.1. For most of its history in the United States, the physical flow of natural gas through gas transmission and distribution systems followed a straightforward
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BOX 14.1
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CENTERPOINT ENERGY: A DIVERSIFIED ENERGY DELIVERY COMPANY
CenterPoint Energy was created in 2002 as part of the restructuring of Reliant Energy into two separate companies: Reliant Resources and CenterPoint Energy. Reliant Resources is now an independent energy service company, while CenterPoint functions as a traditional regulated electric and natural gas business. CenterPoint is one of the largest combination gas and electric companies in the U.S., delivering one or more forms of energy to nearly 5 million customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma, and Texas. The firm’s pipeline and gathering operations serve customers in those states and also Alabama, Illinois, Iowa, Kansas, Kentucky, Missouri, New Mexico, and Wisconsin. CenterPoint is organized into four separate groups: Natural gas distribution, electric transmission and distribution, pipelines and field services, and an electric power generation subsidiary with 60 generating units at 11 electric power-generating facilities and a 30.8 percent interest in a nuclear generating plant. The natural gas distribution group consists of three distribution companies and a commercial and industrial gas services business. Gas group units include CenterPoint Energy Arkla, CenterPoint Energy Entex, and CenterPoint Energy Minnegasco. The gas distribution unit, which serves customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas, makes up the third-largest natural gas distribution system in the United States. Commercial and Industrial Gas Services serves most of its customers in a competitive market basis. Altogether, CenterPoint Energy’s natural gas operations distribute gas to nearly 3 million residential customers and more than 5200 commercial and industrial customers. It operates 97 000 miles of main and service lines that distribute gas to 985 communities. Source:
CenterPoint Energy, 2002 Annual Report.
path, with ownership of the gas passing with custody from producers to pipelines to local distribution companies. In those cases where end users of the gas had a direct connection to a pipeline, the distribution company might be skipped (Energy Information Administration 1996). Restructuring of the
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industry has brought changes to this straightforward system. Today, the physical flow remains the same, but ownership patterns may differ. Local distribution companies purchase gas from producers, marketers, and even from some industrial end users with excess capacity. All of these suppliers are able to arrange separately for the gas transmission. Wholesale energy merchants are a relatively new set of institutions in the industry. These organizations perform some of both midstream and downstream activities. In markets where retail competition is permitted, they perform some of the functions of regulated distribution companies and midstream functions as well. Energy merchants own unregulated assets and/or provide unregulated services. As stated earlier, this segment of the industry is undergoing an extensive reorganization, with a number of firms eliminating merchant trading operations. According to Standard & Poor’s industry analysis Craig Shere (2004), in recent years, many energy merchants have had to weather severe financial distress as their unregulated power assets suffered during a supply glut. Thus, the industry is currently undergoing another structural transition in a new wave of mergers and acquisitions.
MARKETS FOR NATURAL GAS Natural gas is used for many purposes in homes, businesses, electric plants, and factories. Over the 12 months ending in November 2003, natural gas consumption in the four major market segments was divided into the following shares: industrial (including plant fuel and combined heat and power), 36.5 percent; residential, 23.5 percent; electric power generation, 22.7 percent; and commercial, 14.4 percent. In addition, a small but growing market is the transportation industry, including fuel for pipeline pumps and public bases, which consumed 2.9 percent of the natural gas total. Industrial Customers Industrial customers use natural gas for space heating, heat energy in processing applications, for generating steam energy, and as a raw material supplied to a machine or a processing plant. Industries that are highly dependent on natural gas include sugar production and processing, chemical and fertilizer manufacture, and the production of aluminum. The desirability of natural gas among industrial customers is further attributable to the development of new natural gas technologies such as low
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nitrogen oxide emission boilers. More than any other sector, growth in industrial demand is limited by higher natural gas prices. According to Tina Vital of Standard & Poor’s, the spot price for U.S. natural gas was more than $5.80 per million British thermal units (MBTUs) at the end of March 2004. In 2003, the average bid week price was $5.30, and $2.27 in 1999 (bid week prices are a weighted blend of spot and contract prices; a BTU is the amount of heat required to increase the temperature of one pound of water by one degree Fahrenheit). Box 14.2 describes how one investor-owned utility manages its natural gas purchases for power generation. Residential Customers Residential users comprise the second largest group of natural gas users in terms of gas purchased. Residential customers generate the largest share of profits for utilities and make up the largest number of customers. Approximately two-thirds of residential natural gas is used for space heating. Gas is also used to power home appliances, such as stoves, clothes dryers, and fireplace burners. The electricity generation segment is the fastest growing market for natural gas in the U.S. Because it burns more cleanly than coal or oil, natural gas is favored by government regulators and environmentalists. Short-term growth in the use of natural gas for electricity generation is affected by several factors. Weather and the relative prices of natural gas, coal, and oil play important roles, as do the availability of hydroelectric power and the status of nuclear power plants. Natural gas fueled cogeneration and combined-cycle turbine systems are new high-efficiency technologies for producing electricity. Both capture waste heat that may be lost in other processes. A combined-cycle power plant uses waste heat to produce additional electricity; cogeneration systems use the waste heat for space or process heating or for other energy needs.
BOX 14.2
HOW EL PASO ELECTRIC COMPANY MANAGES ITS GAS PURCHASES
El Paso Electric Co. of El Paso, Texas, manages its natural gas requirements through a combination of long-term contracts and spot market purchases. In 2002, the company’s natural gas requirements at the Rio Grande Power Station were met with both shortand long-term natural gas purchases from a number of different suppliers. Interstate gas is delivered under a firm transportation
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agreement (which expires in 2005). The company believes that it will continue to purchase natural gas at market prices on a monthly basis for a portion of the fuel needs at the Rio Grande Power Station for the near term. To complement those monthly purchases, El Paso Electric has entered into a two-year supply contract that began in 2002. In 2002, natural gas constituted 25 percent of the company’s fuel mix, down from 32 percent in 2001, and 33 percent in 2000. Other fuels in 2002 included nuclear, 52 percent of the total, and coal, at 6 percent. Another 17 percent of the company’s power was purchased from other sources. Allocated fuel and purchased power costs are passed through directly to customers in Texas and New Mexico. Source:
El Paso Electric Co., 2002 Annual Report.
Commercial Customers The commercial market consists of a variety of businesses, including restaurants, hotels, public buildings, and large office buildings. As in the residential market, more than half of all commercially consumed gas is currently used for purposes of space heating. Unlike the residential market, gas demand in the commercial market is sensitive to summer weather because many commercial customers use gas for cooling purposes, as well as for heating in the winter. Natural gas is also used as a vehicle fuel and as a component in fuel cells. Longer term, gas-fueled vehicles and fuel cells are expected to become much larger markets. In the U.S., vehicle use rose every year from 1995 through 2003, from 69 140 to 140 935; for 2004, a further 7.5 percent increase was predicted (Shere 2004).
REGULATING THE NATURAL GAS INDUSTRY Before 1978, the natural gas industry faced chronic supply shortages. The federal government set artificially low regulated prices at which producers could sell gas through interstate commerce. However, a series of deregulating laws opened the natural gas industry to market-based pricing and increased competition. Congress passed the Natural Gas Policy Act (NGPA) in 1978. This law deregulated the wellhead price of natural gas. Deregulation resulted in the development in the early 1980s of a competitive wellhead market, including a natural gas spot market.
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However, problems with the deregulated system soon came to light. After arranging low-cost gas purchases directly from gas producers in the spot market, LDCs were often denied capacity (access) by the interstate pipelines for transporting their independently procured gas. As a result, in 1985 the FERC issued Order 436, which required interstate pipelines to transport gas owned by LDCs or end-use customers on a first-come, first-served basis. However, despite open access, pipeline companies retained a competitive advantage over producers through the late 1980s and early 1990s. Because they could combine transportation, storage, and other services, they could provide more reliable service. To alleviate this problem, the FERC then issued Order 636 in 1992. Order 636 required pipeline companies to unbundle their services. Any service a pipeline provides to utilities and other end users – be it gas sales, transportation, or storage – must be offered and priced separately. Once services were priced separately and offered by any number of competitors, consumers could comparison shop for the best price (Shere 2004). The FERC also split off the merchant function from pipelines; pipelines could no longer sell natural gas directly to LDCs or other consumers. Beginning in 1993, marketers and distribution companies were able to negotiate directly with gas producers for their supply of gas and to negotiate prices for each of the unbundled services they would accept from pipelines. Federal regulation of the energy industry began when Congress passed the Federal Power Act of 1935. The FPA, passed during one of the lowest points of the Great Depression, charged the newly established Federal Power Commission with ensuring that an adequate supply of energy was available in all parts of the United States and to do so with conservation of natural resources foremost in mind. Regulation of the gas industry specifically began with passage of the Natural Gas Act of 1938 (NGA). Prior to this, the industry enjoyed relative freedom from regulatory controls (Warkentin 1996). The NGA brought under federal regulation firms that were engaged in the interstate sale of gas for resale. These firms were deemed to qualify for designation as being affected with a public interest. The Federal Power Commission was also ordered to ensure that the wholesale prices for gas to be distributed to residential and business customers were, in the language of the Act, ‘just and reasonable’ (MacAvoy 2000). Deregulation of the industry began in 1985 with issuance of a series of Commission Orders by the Federal Energy Regulatory Commission. The Commission’s intent was to restructure the historical transaction relationships that existed among producing, transmission, and distribution companies. It was alleged that certain combinations of the industry were
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working together to effect discriminatory access to gas transportation pipelines, improve supply, and lower prices. FERC Order 436, the first in the series of deregulation actions, was issued in 1985 to remove discriminatory access to interstate pipelines. The next action occurred with issuance of FERC Order 451. This order did away with a tiered pricing structure of known (called vintage gas) reserves that had evolved after passage of the Natural Gas Policy Act of 1978. Order 451 raised price ceilings of vintage gas to market levels and encouraged gas producers and pipeline companies to renegotiate their contracts. These contracts had, in effect, reduced gas exploration and new well drilling to a trickle – which, in turn, had resulted in a severe gas shortage in some parts of the country. Legal challenges to Order 451 resulted in it being modified and reissued as Order 500. It was again re-worked and finally issued in 1992 as FERC Order 636. This became the blueprint for the nearly complete deregulation of the gas industry that has followed. State Regulation of Natural Gas Rates In most states, utility commissions are responsible for determining the proper rate base and allowable operating expenses for the regulated gas distribution companies in their jurisdictions. Rates for local distribution company customers have generally been set on a cost-of-service basis. In some states, however, commissions have allowed prices in excess of direct costs for some services, and allowed prices below costs for others. State regulators have leaned toward weighting cost allocations toward industrial services, in order to set lower prices for small household customers. The purchased costs of gas and charges for interstate transportation are passed through to final customers. As an illustration of the rate allocation problem, states such as California and New York allocate rate components based on marginal costs of service plus the total costs of specific facilities that provide service only to a specific class of customer. Other states allocate a smaller portion of the overall costs to residential consumers. Instead, some costs may be shifted onto industrial consumers (MacAvoy 2000). Differences among State Public Utility Commissions The public utility commissions (PUCs) of individual states often differ about ratebase determinations of costs and allowed returns. In addition, after the problems in California came to light, the once-active drive toward restructuring the utility industry was reversed in some states. For example, in March of 2000, 23 states and the District of Columbia had implemented
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programs allowing some residential and commercial customers access to the same unbundled services previously available only to industrial customers (MacAvoy 2000). By the end of 2003, full retail competition was only active in five states and the District of Columbia. Statewide unbundling was still being implemented in eight states. Restructuring pilot programs or partial unbundling had been started in eight states, but was discontinued in two others. There was no restructuring underway in 17 states (Mariner-Volpe 2004). As a result of these challenges, multi-state utility holding companies often find it difficult to merge their operations into a single cohesive strategy. An LDC’s earnings from its regulated utility operations are traditionally derived from its allowed rate of return (ROR) on equity invested. However, there is no invested equity involved when an LDC purchases natural gas or electricity from other energy supply firms. This is in contrast with supply a utility develops from sources it owns. When there is no equity invested, there is no associated return for the shareholders. Similarly, the purchase of emissions credits to meet environmental regulations does not provide for any investment return under traditional utility ratemaking. Therefore, traditional ROR ratemaking creates incentives for gas utilities to build pipelines and storage infrastructure and install environmental control equipment, even if third parties can provide the same services at a lower cost to ratepayers. Within each of the four customer classes, rates tend to increase with volume, even though the unit cost to the utility decreases with volume. For this reason, margins are higher on services to use-intensive customers. Moreover, embedded in a utility’s revenue requirement are such ancillary services as providing service to low-income customers and for funding conservation and weatherization programs – programs that provide advice, materials, credit, and in some instances, financial assistance, to customers for installing such products and double-paned windows, weather stripping around doors, insulation in attics, and other weather protection materials. Some states have begun authorizing incentive-based rates that allow a utility to exceed its allowed ROR by meeting such requirements as cost-containment goals and customer service benchmarks (Shere 2004). Some investor-owned gas utilities are seeking to increase shareholder returns with investments in unregulated segments of the industry, such as natural gas exploration and production, energy marketing and trading, and competitive retail energy distribution (Shere 2004). The nonregulated operations of CenterPoint Energy Minnegasco in Minnesota are an example of this activity. Called ‘Home Service Plus®,’ it is the largest furnace and
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appliance repair firm in Minnesota, with more than 1 million appliances maintained for more than 235 000 customers. The company also provides a security monitoring service to more than 12 000 customers, and is the largest provider of heating, ventilating, and air conditioning equipment and supplies in the state.
MONITORING NATURAL GAS PRICING Natural gas managers are concerned with three pricing levels: wellhead pricing, citygate pricing, and end-use pricing. The average wellhead price is the average price received by producers from all sales excluding all other charges added for processing, storing, transporting, and delivering gas. Before 1978, producers sold mainly to pipeline companies. Today, producers sell large amounts of their gas to marketers or directly to end users, and very little to pipeline companies. Wellhead prices are closely monitored by the FERC and reported in the Natural Gas Monthly issued by the Energy Information Administration. Restructuring of the industry has had significant effect upon both the supply and the price of natural gas. From 1978 to 1988, gross production of natural gas declined 1.46 percent, while wellhead prices increased 11.6 percent. In contrast, from 1988 through 1994, gross gas production increased by 12.28 percent, while real wellhead prices dropped by 8.5 percent. However, once demand and production neared balance, demand growth became more dependent on weather patterns and growth of the economy. From 1994 through 1999, gross production increased just 1.3 percent, while real wellhead prices grew 8.3 percent (Shere 2004). Traditionally, citygate prices referred to the price of gas at the point where a local distribution company took possession. Since restructuring of the industry, citygate prices now include producers’ sales at the citygate to LDCs and marketers, marketers’ sales at the citygate to LDCs, and sales at the citygate by producers and marketers to end users. Generally, citygate prices include the wellhead price for the gas, pipeline transportation costs, and if relevant, any fees charged by a wholesale marketer. Transportation costs can include a number of other items, including storage costs, taxes, reservation charges, and other costs associated with transportation. End-use prices can be either the LDC’s price to on-system customers or the price to off-system customers charged by wholesale marketers. These prices usually vary with volume. Finally, retail competition has resulted in the development of a new concept in pricing: price at the burnertip. Burnertip prices are prices charged by nonregulated utilities to residential customers.
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THE ROLE OF STORAGE CAPABILITY Cleaned and processed natural gas is often transferred from the reservoir in which it is discovered to other reservoirs, usually closer to market areas, where it is stored until needed to meet market demand. Three types of underground storage facilities are used: depleted production basins, aquifers, and salt caverns (Trapmann 2004). Gas storage is one of the midstream assets that are extremely important to natural gas marketers and traders. Depleted fields comprise the great majority of the underground reservoirs, accounting for 82 percent of total capacity. Aquifers make up 15 percent, and salt caverns add another 3 percent. Illinois and Indiana contain 66 percent of all aquifer fields; Texas and Louisiana hold 69 percent of all salt cavern reservoirs in the U.S. Owning or controlling gas in storage allows marketers and LDCs to guarantee future deliveries. Another benefit is that it allows distributors to actively manage inventories against fluctuating natural gas prices. A utility can manage its inventory by purchasing gas at low prices and storing it until it can be sold at a higher price. The right to purchase gas from the reservoir as needed (for which a capacity payment is made even if no gas is drawn) can also be sold to a third party. The reservoir owner can also lease the storage space to other organizations in the supply chain. Storage also reduces reliance on transmission pipeline capacity, which is at or very near to capacity globally. According to the Energy Information Administration (Trapmann 2004), total underground gas storage capacity measured 8207 billion cubic feet (Bcf) in 2002. Just four states hold more than 41 percent of this capacity: Michigan, with 12.6 percent of the total; Illinois, 11.5 percent; and Pennsylvania and Texas, with 8.7 and 8.5 percent respectively. Experience has shown that storage capacity is a critical component in the natural gas distribution sector. A gas shortage during the winter of 2000–01 saw dramatic price spikes in the spot market. Some of the shortage and price increases might have been avoided had the industry fully utilized existing storage capacity during the previous summer season. When production rose to meet demand, the crisis was soon resolved: ‘When the industry responded with increased production, it was amazing how fast the current storage infrastructure ran out of room; and how fast the price went down in response’ (Craddock and Hogue 2004, p. 60). In the past, natural gas producers filled storage during the summer months, when there was less demand pressure on pipelines and the cost of natural gas was lower. The stored gas was then removed from storage during the colder winter months to fill peak-day demands. However, today natural gas is increasingly being used in the summer months to meet air
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conditioning demand. As a result, summer gas prices do not drop the way they did in the past. In fact, some industry observers now predict that gas-fired power generation may soon cause a summer demand peak that balances out the winter peak. Numerous gas storage projects are being planned to accommodate increased gas usage and to improve reliability. The added storage capacity is likely to result in additional gas purchases during off-peak months to fill the storage fields in advance of the next winter season. In areas like New England and the coastal areas of the Middle Atlantic seaboard states, few underground storage opportunities exist. Many utilities in these regions are developing liquefied natural gas (LNG) storage facilities for supply during severe cold snaps. Additional LNG port and storage facilities are also on the drawing board.
PROJECTIONS FOR FUTURE SUPPLY According to the American Gas Association, the 48 contiguous U.S. states have an abundant resource base of natural gas – enough to last until the second half of the present century. Nonetheless, natural gas production is expected to continue at levels that fall short of annual demand for the foreseeable future, making supplemental sources of gas necessary to meet everyday demand. Supplemental sources include pipeline deliveries of Alaskan and Canadian natural gas and overseas imports of liquefied natural gas (Shere 2004; Vital 2004). In addition to the decline in North American natural gas reserves, major trends in the industry include (1) increasing globalization, (2) growing demand in Asia, and (3) limited pipeline capacity worldwide. By 2005, traditional producing areas in the U.S. are expected to be able to provide only 75 percent of the country’s gas needs. The deficit is expected to be made up by liquefied natural gas imports and Arctic gas. Most of the supplemental supplies are expected to come from Canadian pipeline deliveries (Vital 2004). Although Mexico has a considerable natural gas resource base, the nation’s domestic demand is anticipated to keep pace with the development of its natural gas infrastructure. Pipeline exports to Mexico nearly doubled to 263 Bcf in 2002. Gas is exported to Mexico at 11 border crossings, located in Texas, Arizona, and California. LNG: The Supply Source for the Future? LNG is natural gas that has been cooled to about minus 260 degrees Fahrenheit. At this temperature, it changes into a liquid state that can be
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stored in insulated tanks. LNG is transported from overseas production centers in specially built ships. At the destination port, the gas is unloaded from ships to receiving terminals, where it is stored and regasified for distribution to pipelines, marketers, or end-user customers (Costello 2003). The supply chain of LNG incorporates four major components: (1) gas field development, (2) a cooling for liquefaction process, (3) tanker transportation, and (4) a receiving, storing, and regasification terminal. All facilities in the supply chain are highly capital-intensive. Today, the United States imports LNG from Trinidad and Tobago, Qatar, Algeria, Nigeria, and Oman. In 2003 there were only four LNG regasification terminals in the U.S., with a total base load capacity of about 2.3 Bcf per day, and a peak load send-out of about 3.2 Bcf. The oldest of these terminals, which began operations in 1971, is located in Everett, Massachusetts, near Boston. The terminal is being expanded to serve a new electric power generator located nearby. Other terminals are the Elba Island Terminal near Savannah, Georgia; the Lake Charles Terminal in Louisiana, and the Cove Point Terminal in Maryland. Lake Charles Terminal was completed in 1982, but operated for only a short period before it was closed; it was reopened in 1999 and, in terms of storage capacity, is now the largest LNG import terminal in the United States. Cove Point was completed in 1978, but operated only until 1980; it was reactivated in 2003. In addition to these four terminals, an LNG facility in Alaska processes gas for export to the Japanese market. Because very little is imported from overseas, natural gas has been promoted as a strategic factor in developing energy independence. Moreover, of the gas that is imported, nearly 70 percent of the imports in 2002 came from non-OPEC countries (Shere 2004). It is not expected that LNG will soon alleviate the growing shortages of natural gas in North America. The few existing terminals and the very high costs of adding new facilities are likely to serve as a damper on growth in this sector for some time. The following statement may summarize expectations currently held on the growth potential for LNG: Liquefied natural gas (LNG) will provide some supply, but it is not expected to provide enough supply to remedy [the] imbalance [between supply and demand]. However, it will either be base loaded to help recover the huge infrastructure investments, or, if a spot market for LNG cargoes develops, LNG may be more plentiful in the summer, when there is less competition from the predominantly northern-hemisphere worldwide LNG markets. Regardless, LNG would not seem to be a solution for market imbalances. (Craddock and Hogue 2004, p. 62)
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SUMMARY Since 1996, gas distributors and customers have benefited from lower transportation charges, greater and more reliable supplies, and – until recently – generally lower final prices. Demand for natural gas to fuel electricity generators and for industrial processes continues to expand. Even as demand is increasing, the maturing of traditional North American production fields in Oklahoma, Texas, and the Gulf Coast has reduced domestic supply. Together, this tightly balanced supply and demand situation has caused natural gas prices to rise to nearly record highs. Gas prices have risen and fallen far more rapidly than other energy supplies. Many of the companies that made significant investments in unregulated activities were badly burned by the 2001 and 2002 collapse of a number of energy merchant companies, led by the experiences of Enron. Many large holding companies have eliminated or severely curtailed their energy merchant operations. The natural gas industry is divided into three categories of activities: upstream activities, midstream activities, and downstream activities. Upstream activities are performed by exploration and production and drilling companies that explore for gas and pump it out of the ground. Midstream activities include the gathering of gas, processing it into its component hydrocarbons, and storing it for later transmission or other use. The transmission of natural gas by interstate pipeline is also generally considered a midstream function. Downstream activities include the transportation of natural gas to end users by local distribution companies (gas utilities). LDCs may be owned either by equity shareholders or by a local government such as a city, county, or special utility district. LDCs purchase, transport, distribute, and resell natural gas to end users, including residential, commercial, industrial, and, increasingly, companies that use gas as a fuel for generating electricity. Traditionally, the flow of natural gas through gas transmission and distribution systems followed a straightforward path, with ownership of the gas passing with custody from producers to pipelines to local distribution companies. In those cases where end users of the gas have a direct connection to a pipeline, the distribution company might be skipped. Restructuring of the industry brought changes to this system. Today, the physical flow remains the same, but ownership patterns may differ. Local distribution companies purchase gas from producers, as do marketers, and end users, all of whom must arrange separately for its transmission. LDCs and marketers then resell the gas to their customers. Wholesale energy merchants are a relatively new set of institutions in the industry; they perform some or both midstream and downstream activities.
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Natural gas is used in homes, factories, electric plants, and businesses. In 2003, natural gas consumption in each market segment was: industrial, 36.5 percent; residential, 23.5 percent; electric power generation, 22.7 percent; and commercial, 14.4 percent. The transportation industry, including pipeline fuel, consumed 2.9 percent of the total. Industrial customers use natural gas for space heating, heat energy in processing applications, for generating steam energy, and as a raw material supplied to a machine or a processing plant. Industries that are highly dependent on natural gas include sugar production and processing, chemical and fertilizer manufacture, and the production of aluminum. Residential customers generate the largest share of profits for utilities and make up the largest number of customers. Before 1978, the natural gas industry faced chronic supply shortages. The federal government set artificially low regulated prices at which producers could sell gas through interstate commerce. Congress passed the Natural Gas Policy Act in 1978. This law deregulated the wellhead price of natural gas. Deregulation resulted in the development in the early 1980s of a competitive wellhead market, including a natural gas spot market. FERC Order 436, issued in 1985, required interstate pipelines to transport gas owned by LDCs or end-use customers on a first-come, first-served basis. The FERC issued Order 636 in 1992, requiring pipeline companies to unbundle their services; any service a pipeline provides to utilities and other end users had to be offered and priced separately. Natural gas managers are concerned with three pricing levels: wellhead pricing, citygate pricing, and end-use pricing. In most states, utility commissions determine the proper rate base and allowable operating expenses for regulated gas distribution companies in their jurisdictions.
ADDITIONAL READING MacAvoy, Paul W. (2000), The Natural Gas Market: Sixty Years of Regulation and Deregulation, New Haven, CT: Yale University Press. Shere, Craig (2004), Natural Gas, Standard & Poor’s Industry Surveys, May 13. www.netadvantage.standardandpoors.com/docs/indsur///ngd Trapmann, William (2004), The Natural Gas Industry and Markets in 2002, Washington, DC: Energy Information Administration, Department of Energy.
15.
Challenges in the water and wastewater industries
Water is one of life’s absolute necessities. Without a steady supply of clean, fresh water, cities could never have been invented, let alone thrived. When the water source went bad, disease and death followed. Because of this, some of the earliest civil engineering feats were the building of aqueducts to bring clean water from its distant source to where it was needed by town dwellers. The development of these water systems is what made the world’s early civilizations possible. The societies that evolved in such locations as India, Mesopotamia, and the Western Hemisphere were often founded on huge, communal water collection, transmission, and distribution systems for irrigation, human consumption, and, equally important, for flood control. Water and wastewater systems are the sine qua non of all modern civilizations. The early water systems in the U.S. were developed because existing town and private wells where most people drew their water were either (1) inadequate to meet the needs of a growing population, (2) subject to periodic pollution and carriers of many water-borne fatal diseases, or (3) unable to supply enough water for fire suppression, or for all three reasons. The first water system in Colonial America was established in Boston in 1654 and was used for both fire protection and domestic use (Glaeser 1957). The system drew its supply water from several springs, but these eventually proved to be inadequate to meet the needs of the growing city. In 1796, when the population of Boston passed 20 000, a private system was franchised to supply the city’s water needs. Water was drawn from a pond five miles away and carried by aqueduct to town. The second water system in the U.S. was opened at Bethlehem, Pennsylvania, in 1762. That system drew water from wells and pumped it into city mains for distribution. The first successful large municipal system was begun in Philadelphia in 1798, when the city had a population of more than 80 000. This system was the first to use large steam pumps for water pressure and cast-iron water mains for distribution. From the 1800s on, the municipally controlled system would be the most common way to install water systems. Wastewater systems were slower to evolve, but this too would soon follow the municipal ownership model. 252
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Unlike the few very large companies that dominated the telecommunications and energy utility industries, the water industry has remained in the hands of single-city municipal systems or a few relatively small companies (Crew and Kleindorfer 1986). Recently, however, a wave of consolidations has resulted in a number of horizontally integrated, often global, giants emerging in the industry. Many of these large water and wastewater operating firms are either French or British.
PARTICIPANTS IN THE WATER INDUSTRY Most of the organizations that together make up the water industry may be grouped into the following six categories. Because many of these organizations serve more than one market, placing an organization into a single category is an arbitrary decision. One category in the list – private system operators – are relatively new to the United States, although they have been operating successfully in Europe for some time. These organizations operate one or more municipal systems under private contract, which may last from 10 to 20 years, and include provisions for one or more contract extensions. The several types include: ● ● ● ● ● ●
Municipal water suppliers Agricultural water suppliers Federal agencies State water agencies and projects Municipal wastewater collection and treatment agencies Private and public toxic treatment organizations.
These participants have evolved to meet a wide variety of differentbut-related objectives. Some were established to lower the cost and risk of the development of water resources. Others were formed in order to store and distribute water to residential, commercial, industrial, or agricultural water users, while others were formed for the purposes of collecting, treating, and disposing of polluted water. Still others were formed with the objective of improving the management of water resources, including groundwater. And still another purpose is to take advantage of special legal powers available to water districts and utilities; for example, government water districts are able to use condemnation powers to take control of private water rights land for the public good, and to tax local property and issue tax-exempt bonds for water project development (Sax et al. 2000). Box 15.1 describes events in a small municipally owned and operated typical water district activities water system.
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The U.S. Environmental Protection Agency (EPA) classifies water systems into three categories by ownership: public, private, and ‘ancillary.’ Ancillary systems are very small systems, usually privately owned, that provide water to some small enterprise such as a business or a mobile home park. Ancillary systems serve less than 1 percent of the total U.S. population; private systems serve 13 percent; and public systems serve 86 percent of the population. Table 15.1 shows the breakdown of system types and revenues as of 1995. Municipal Water Systems At the beginning of the nineteenth century, nearly all city dwellers drew their own water from public wells or from wagons that delivered water to individual customers. Periodic outbreaks of illnesses such as typhoid and water shortages in the face of rapid growth led to the development of a few water systems by private firms. Criticism of their exorbitant rates and service only to commercial and the more wealthy parts of town resulted in a few cities taking control of the systems from private interests. The first successful municipal water system began operations in 1798 in Philadelphia, when growth of the city required a larger, more reliable supply of fresh, clean water. City fathers responded by damming the Schuylkill River and bringing water to the city by surface aqueduct. The first metropolitan system in New York was begun in 1774, but was never completed. A private corporation started a small New York system in 1799 which, by 1823 had grown to more than 25 miles of water mains and 2000 customers. New York City began its first small municipal system in 1830. By 1842 demand had grown large enough to justify construction of a 40-mile aqueduct that brought fresh water into the city from the Croton River. Other large cities soon followed, including Boston, Denver, Los Angeles, San Francisco, and many others (Glaeser 1957). In addition to municipal systems, many counties also provide water to rural and small town water users. These systems are managed by county utilities departments, which provide other services as well, including waste water collection and treatment, storm water runoff, and solid waste collection and disposal. Public and private municipal water systems supply more than 80 percent of the nation’s residential and commercial water users and close to 20 percent of the industrial water users. Although there are more private companies, publicly owned systems serve by far the most customers; something like 85 percent of all water system customers get their water from publicly owned systems. A distinct trend toward several forms of out-sourcing
Water and wastewater
BOX 15.1
255
SUPPLYING WATER TO THE CITIZENS OF LACEY
Making sure that enough water to meet local demand is available is a concern of water system managers everywhere. Many system managers and city administrators and policymakers must regularly take steps to capture the control of the water resources they will need to supply existing customers and meet growth in demand expected in the near future. The small town of Lacey, Washington has projected that by 2008, the utility will not have enough water from existing groundwater sources to meet expected demand. Since 1987, Lacey has purchased water from nearby Olympia at 23 cents per 100 acre feet.Water in bulk amounts is typically measured in ‘acre feet.’ One acre-foot of water is the amount needed to cover one acre to a depth of one foot. Water at the individual home or commercial establishment is usually measured in gallons. Water flow in distribution lines is usually measured in gallons per minute. This agreement comes up for renegotiation every ten years. The City Council has applied to the State Department of Ecology for permission to sink new wells to increase pumping capacity and increase water supply. Approval of the request is expected to take at least five or more years. All water for this town of approximately 16 000 residents is pumped from local wells; amounts are limited by established water rights, which are strongly upheld in all of the Western States. The city is scrambling to locate and acquire, if possible, new sources anywhere it can. It is doing this in two ways. One way is by buying up all available private water rights to the local aquifer. Most recently, for example, when a local property owner offered to sell her 460-acre feet of water rights to the city for $414 000, the utility jumped at the opportunity. The property, once a small family farm, is now being developed for industrial and commercial uses. City water lines were already installed adjacent to the property, leading the property owner to conclude that the need for the small private system was no longer necessary. Addition of the private rights represents immediate addition of more than 6 percent of the city’s total existing primary water right of 6991 acre-feet per year. Source:
Christian Hill (2004), The Olympian, September 15; July 27.
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Table 15.1 U.S. community water systems by ownership type, population served, and annual revenue (1995)
Ownership
Count
Percentage of total
Public Private Ancillary
21 789 16 540 11 960
43 33 24
Percentage of total population served
Annual revenue ($billion)
86 13 1
22.2 3.7 n/a
Source: Seidenstat et al., 2000, p. 6.
the operations and management of municipal water and wastewater systems is, however, rapidly taking hold in the United States. This trend will be discussed in greater detail in the section of competition and privatization later in this chapter. Most U.S. wastewater systems are municipally owned, and have been so from their beginnings. In 2000, there were 16 255 municipal treatment systems and 21 167 municipal collection systems in the country. Together, these treatment and collection systems served nearly 72 percent of the total U.S. population (Seidenstat et al. 2000). Agricultural Water Suppliers A number of different types of organizations have evolved to develop and manage irrigation systems. In the arid Southwestern states, irrigated agriculture has a long history. The earliest irrigation canals in the West were constructed by Native American tribes as communal activities. When the Spanish moved in during the eighteenth and nineteenth centuries, they continued the communal approach with development of community acequias, or irrigation canals. These were maintained by users of the water under the direction of an elected mayordomo, or ditch boss. These organizations still function in New Mexico, and often serve as a central focus of many rural communities (Sax et al. 2000). When Mormons immigrated to the American West, the church took on this role, developing irrigation systems and allocating water. By 1850, more than 16 000 acres of farmland were watered by the Mormon systems. The Church-dominated Utah legislature passed a law in 1865 that allowed a majority of citizens in a county to form an irrigation district, with power to acquire land and levy taxes. After the U.S. Civil War, new organizations evolved to supply water. As settlers moved farther from water sources, land promoters sometimes
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formed companies to bring water from distant sources. These early carrier ditch companies were often poorly planned and managed, and soon disappeared. Today, few privately financed carrier ditch companies remain; they are only important in California and Texas. Mutual water companies have replaced most of the earlier suppliers of water for agricultural purposes. These cooperative water organizations are similar to the Spanish acequias and the Mormon community projects. Irrigators organize a non-profit company to build ditches and bring water to the farmers’ fields. Each member owns stock in the company proportionate to the water each will receive. In dry years, cutbacks follow the same pattern. Members pool resources and pledge their lands as collateral in order to raise capital. Nearly 85 percent of all irrigation water organizations in the Western states are mutual water companies; they supply water to something like 20 percent of all irrigated acreage and some communities. They are particularly important in Colorado and Utah, where they serve 70 and 90 percent of irrigated acreage respectively. Water Districts Irrigation districts are local governmental organizations that provide water to farmers within their district boundaries. They are governed by an elected board of directors; the ‘stockholders’ are the district electorate. The chief power of water districts is the ability to condemn riparian water rights (riparian rights are reserved to owners of property that abuts the water source). They also have the power to condemn land, tax local property, and sell bonds secured by their taxing authority. Another type of water district is the conservancy district, which coordinates water use in a single watershed. They have also been formed to manage groundwater withdrawals. Irrigation districts supply nearly 25 percent of all the irrigated acreage in the Western United States, and more than half of the irrigated acreage in California and Washington State. In addition, water districts supply water to large numbers of domestic, commercial, and industrial water users. One of the largest is the Southern California Metropolitan Water District, which imports and distributes water to smaller districts and municipal operations in its area of operations. Water districts are empowered to collect water, build reservoirs, canals and other irrigation works, and distribute water to the district’s residents. Most districts are also authorized to provide a number of related services, such as the production and sale of hydroelectric power.
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System challenges
Government Water Agencies Involvement of the federal government in the water industry began in the nineteenth century with U.S. Army Corps of Engineers projects to enlarge and improve waterways for transportation. The first effective federal irrigation involvement came after passage of the Reclamation Act of 1902. Under this legislation, the federal government would construct irrigation projects and sell water to western farmers. Proceeds from these sales were to be used over a number of years to pay off the government’s costs, interest free. The Bureau of Reclamation (BOR) was established in 1902, under the Department of the Interior, to implement the provisions of the Reclamation Act. One hundred years later, the Bureau is the largest wholesaler of water in the country and second largest producer of hydroelectric power in the Western U.S. The Bureau’s water projects bring water to more than 31 million people, and provide one out of every five farmers in the 17 Western states with irrigation water for 10 million acres of farmland. BOR develops, manages, and protects water and related resources, serves as the fifth largest electric utility in the West, and administers nearly 350 reservoirs, 58 hydroelectric power plants, and more than 300 recreation sites. As of 2000, the Bureau had constructed more then 600 dams, 16 000 miles of canals and aqueducts, 280 miles of tunnels, 50 hydroelectric generators, and 140 pumping stations. Current programs include environmental protection; water conservation; water recycling and reuse; and developing partnerships with customers, state governments, and Native American tribes (BOR 2004). State Water Projects Other than California, the states have played a secondary role to the federal government in the development of water resources. California’s State Water Project supplies something like 2.5 million acre-feet of water in a normal year to municipal and agricultural water districts. The California project includes nearly 30 reservoirs, five hydroelectric generating plants, 650 miles of canals and pipelines, and 20 pumping plants. Water from Northern California is lifted across the Tehachapi Mountains and delivered through tunnels to augment domestic supplies in Southern California. State projects for irrigation have also been developed in Montana, Texas, and Utah.
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LEGISLATION CONTROLLING THE WATER INDUSTRY Two pieces of federal legislation passed early in the 1970s resulted in significantly greater control over the way Americans dealt with waste water and the extent to which the Federal government would be involved in protecting the nation’s drinking water. The first of these was the federal Water Pollution Control Act of 1972. Almost immediately, this law became commonly referred to as the Clean Water Act. This law gave the Environmental Protection Agency the authority to implement pollution control programs and to set water quality standards for contaminants in surface water – it was designed to clean up rivers, streams, and lakes. The Act also set increasingly stringent rules for construction of sewage treatment plants, while at the same time, provided large grants for new plant construction. The Act has been amended several times since its passage. The second of these water quality laws was the Safe Drinking Water Act (SDWA), originally passed by Congress in 1974 to protect public health by regulating the nation’s drinking water supply (potable water). Initially, SDWA focused on treating water destined for human consumption. Amendments in 1986 and again in 1996 changed the law’s focus on treatment to include ensuring safe, clean drinking water at the source. Under CWA rules, individual states are required to monitor the total maximum daily loads (TMDLs) of substances and chemicals in their waterways. In addition, states must ensure that water does not exceed the TMDLs set forth in the Act. Not all states have the ability to comply with these provisions. For those that do not, the Environmental Protection Agency (EPA) is supposed to perform the service. A 1981 change improved the capabilities of treatment plants constructed under a city grants program. Changes in 1987 eliminated the grants program, substituting the State Water Pollution Control Revolving Fund (also called the Clean Water State Revolving Fund), which used EPA–state partnerships to fund projects. The objective of the Safe Drinking Water Act was protection of public health by regulating the public drinking water supply. The law required the EPA to set national health standards for drinking water to protect against naturally occurring and human-made contaminants. The law has been amended twice, first in 1986 and again in 1996. The 1996 amendment recognized source water protection, operator training, funding for water system improvements, and public information as important components of a safe drinking water system. SDWA applies to nearly every public water system in the nation. The only systems excluded are those with fewer than 15 service connections or which serve fewer than 25 customers per day for
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at least 60 days of the year. At the end of the twentieth century, more than 170 000 public water systems fell under SDWA jurisdiction. Most of the regulatory oversight of water systems is carried out by state drinking water programs. States are able to apply to the EPA for ‘primacy,’ which is the authorization to implement and control SWDA programs within their jurisdictions, provided they can show that their standards are at least as stringent as the federal standards. They must also ensure that all their water systems meet those requirements. Only Wyoming and the District of Columbia had not received primacy status by 2000. Water standards are established through a three-step process. First, EPA identifies harmful water contaminants. Second, it determines a maximum goal for each contaminant, below which there is no known or expected risk to health. Third, it specifies a maximum permissible contaminant level for drinking water delivered to any user of a public water system. These levels are enforceable standards and are set as close to the goals as possible. EPA also proposes appropriate treatment techniques. Water utilities must follow the EPA standards and provide an annual report of their progress, including measurements of all listed contaminants found in their water supplies (EPA 1999). The 1974 Act established a standards-based approach to regulating chemical and microbiological contaminants in water. The Act also spelled out responsibilities for federal and state governments over local water utilities. Amended several times since 1975, a tradition of standards and rules have evolved which govern an increasing number of contaminants, stricter limits on contaminant concentrations, specifications for treatment technologies, and monitoring and reporting requirements. Amendments in 1996 required the EPA to develop implementation guidelines for all states. Water Collection, Storage, and Distribution Fresh water is taken from two chief sources: (1) streams, rivers, lakes, and runoff that constitutes the surface water systems, and (2) the groundwater that must be pumped from underground aquifers. There is something like 30 times more fresh water in underground aquifers than there is in all the rivers, streams, and lakes on earth (Glennon 2002). Approximately 96 percent of the earth’s water is in the oceans and is too salty to drink or to use for farm irrigation. Of the remaining, about 1 percent is considered ‘brackish’ – less salty than sea water; it can be used to irrigate some crops but is too salty for human consumption. Close to 2 percent remains frozen, although this proportion may be declining as the polar ice caps continue to melt faster than they are replenished. The less than 1 percent remaining that is considered drinkable and accessible is con-
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tained in lakes and reservoirs, wetlands, rivers and streams, in underground aquifers, or as moisture in the air. In overall quantity, the United States has more than enough water to meet its existing offstream needs (water withdrawn for residential, commercial, industrial or agricultural uses), while still retaining most of the water instream. In a typical year, rain and snow contribute to average stream flows of 1380 billion gallons per day. This is more than four times the amount of water now withdrawn, and more than 13 times the amount of water that is actually consumed. The problem is that much of this water is not where people want it or when it is wanted. For example, the eastern half of the United States has enough rainfall so that the majority of farmers can grow crops without irrigation. However, in the bulk of the western half of the country, the reverse is true. In addition, there is wide variation within each area and from year to year. Farmers, commercial and industrial water users, and municipal water suppliers in the western half of the country have for a long time met an increasing proportion of their water needs by pumping groundwater. Groundwater is runoff from rain and snow that has trickled down into underground aquifers. Some 60 billion gallons per day are returned to these aquifers annually. Yet, groundwater pumping in many locations exceeds the ability of nature to replenish the aquifers. Groundwater now supplies more than 40 percent of the public-supplied water for residential use, and 23 percent of all fresh water used. In certain parts of the country – particularly in the Great Plains and Southwest – water tables have dropped dramatically; levels in Texas have declined by an average of 1.35 feet per year since 1992. Declining water tables often result in compaction of the aquifer and sinking surface soil. In portions of California’s Central Valley, for example, the land has dropped nearly 30 feet over the last 50 years. Difficulties Interconnecting Systems In most cases, water cannot be economically transmitted over long distances, nor is it practical to connect water or wastewater systems into largescale grids as is done with electricity. Water and wastewater simply do not travel well, as the following statement explains: In the water and wastewater industries . . . ‘wheeling’ of the product across large distances is not as technologically feasible as in the energy industries. Power costs for pumping through gravity-flow pipelines can be high, drinking water quality can degrade over time and distance, and water from different sources may not react well upon mixing. Similarly, with wastewater, long distances can increase the risk of flows going septic. (Seidenstat et al. 2000, p. 17)
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One solution to the challenges of collecting and transmitting water resources has been successfully implemented by the creation of Tampa Bay Water as a purely wholesale water utility. In 1996, the Florida legislatures directed the utility and local governments to evaluate regional water needs and make recommendations for ways to ensure future supplies for all concerned. Tampa Bay Water was given control of all water supply and transmission infrastructure, including more than 100 production wells and 160 miles of transmission mains with a capacity as much as 365 million gallons per day. The infrastructure includes: (1) hydrological and ecological monitoring stations, (2) well pumps, (3) chemical storage, (4) feed process control equipment for water treatment, (5) storage tanks, (6) large diameter pipelines, (7) meter stations, and (8) a supervisory control and data acquisition system. The system has an annual budget of more than $13 million and supervises something like $25 million in capital improvements annually (Rogoff et al. 2002).
WATER INDUSTRY MANAGEMENT CHALLENGES Water and wastewater utility managers face a number of important challenges as the new century begins. Among the more salient of these are challenges relating to privatization and competition, infrastructure modernization and development, and security challenges that came to light after the September 11, 2001, terrorist attacks on the World Trade Center in New York City and the Pentagon. Each of these is discussed in greater detail in the following pages. Privatization and Competition in the Water Industry While it has been occurring at a much slower pace than in the energy industries, competition has established a strong foothold in the makeup of the global water and wastewater industries (Nadol et al. 2000). Most observers believe that we can expect the pace of privatization and competition to accelerate during the early years of the new century. According to one group of water system consultants: [C]ompetition internally and externally has become not just a reality, but a force likely to change the entire [water] industry in the early years of the twenty-first century. (Dysard 2001, p. 85)
Initially, municipal water and wastewater systems developed in response to public health threats. The exceptionally high capital costs for water and wastewater systems, together with the government’s access to capital at
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lower interest rates, essentially dictated that investments in water and wastewater infrastructure be carried out by governmental bodies rather than investor-owned utilities. Municipal systems dominated the industry until the last decade of the twentieth century, when the costs of complying with EPA-mandated environmental standards became greater than aging domestic systems could finance. Because they bring outside capital to fund these needed improvements, international water holding companies are playing a growing role in the U.S. water and wastewater industries. These organizations typically operate in more than one country and provide more than one level and/or type of service (see Box 15.2). In the 1980s, fewer than 200 municipal systems were being operated by private contractors. By the end of the 1990s, the EPA estimated that more than 1200 systems in 44 states and Puerto Rico were under operations and management contracts with private suppliers.
BOX 15.2
VEOLIA ENVIRONMENT OF PARIS: A WATER MULTINATIONAL FIRM
Veolia Environment provides water and wastewater management services to governments, industries, and commercial and residential customers around the world, and operates a number of energy and transportation services. Founded in Paris in 1853 as the Compagnie Générale des Eaux, the firm began operations by developing and operating municipal water systems in Nantes (1854), Nice (1864), Paris (1860), Constantinople (1882), and Porto, Portugal (1883). It began operating water treatment plants in 1884. Veolia continued exclusively in the water business until the 1980s, when it acquired a waste management and transportation service firm and an energy services provider. Acquisition of several communications and media companies followed in the 1990s. The now-diverse company changed its name to Vivendi in 1998 and renamed its main water subsidiary the Compagnie Générale des Eaux, a memory of its earliest beginnings. In 1999, the company name was changed to Vivendi Environment and to Vivendi Universal in 2000. In addition to its ongoing business, Veolia received contracts in 2002 that, over the life of the contracts, were expected to provide nearly $34 billion (€30 billion) in total revenue (€1⫽$1.12). Highlights of the new business included: ●
A €390 million contract to modernize a wastewater treatment facility that handles portions of Paris’s wastewater;
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●
●
●
●
●
●
●
●
€360 million for industrial wastewater treatment for a packaging firm; A €1.5 billion contract to design, construct, and operate wastewater treatments plants for The Hague in the Netherlands; A $1.5 billion contract for outsourced management of municipal water for Indianapolis, U.S.; A €4.6 billion contract for management of water, wastewater, and electricity services for the Rabat-Salé region of Morocco; A €10 billion contract for the management of water services in Pudong, China (a Shanghai business area); A seven-year contract renewal to collect residential and commercial waste and urban cleansing service in the London, UK areas of Westminster and Camden, together worth over €340 million; A €10 million for management of industrial waste at 670 sites in Australia; Contracts in Savannah, Georgia, and Charleston, South Carolina, to operate waste-to-energy plants; And other contracts in Belgium, Chile, the Czech Republic, and elsewhere.
Source:
Veolia Environment, 2002 Annual Report (Form 20-F).
CHALLENGES IN INFRASTRUCTURE MANAGEMENT Many of the most severe challenges facing water and wastewater utility managers are simply the result of a system infrastructure that is collapsing from old age, over-use, and too many years of deferred maintenance. Service area population growth has required scrambles for resources to pay for system expansion. Exacerbating these infrastructure age problems are a number of federally mandated improvements which must be made in the systems to meet increasingly strict public health, environmental, and pollution control measures. And, last but certainly not least, are challenges in finding the means to pay for the estimated $470 billion cost of the improvements and expansions needed to meet these and other problems. Among the challenges that water and wastewater must resolve in the next several decades are: ●
Meeting the federal regulatory requirements that include installation of expensive water quality monitoring systems for fresh water, and to
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monitor and control effluent discharges, or face the promise of serious penalties for noncompliance; Catching up with the erosion of their systems caused by decades of use and too much deferred maintenance in the past; Increasing political resistance to rate increases – increases that are needed to pay for the huge cost of complying with health and environmental requirements. Communities facing financial crises resulting from taxpayer ‘revolts’ are unable to pay for needed investments.
Since 1995, managers in municipal water utilities – regardless of their ownership system – have had to make a number of painful decisions in order to continue to serve their communities. The easiest decision has apparently been to make reductions in their staff. A 1998 survey of the industry revealed that many of the utilities that responded to the survey chose this path as the way to cut costs. In many cases, this decision to cut staff is coming back to haunt administrators as they try to make needed improvements to their systems. Utility managers now see the inadvisability of wholesale staff cuts without proper planning and analysis of the entire system and all possible alternatives. More utilities are adopting other means of meeting their declining revenue/rising expense challenges. The most popular approach has been to privatize portions of the system, including outsourcing such activities as meter reading, billing, and customer service, among other support services. Others have increased their investments in automated systems, turned to design-build-operate contracts with private firms, alternative delivery systems, and public/private partnerships (PPPs). PPPs seem to hold the greatest potential for aiding water and wastewater system managers to meet their growth and rebuilding needs. The PPP industry is characterized by a number of large, multinational engineering firms bidding against one another for business – thus introducing the competition that promises to keep prices low. There has been a greater than 20 percent annual growth in this activity since the mid-1990s, with double-digit growth also predicted for the foreseeable future. R.W. Beck Company’s 1998 survey found that 35 percent of the municipal operations surveyed were planning some form of PPP contract in the near future. The report prepared from this survey made the following prediction: The water and wastewater industry is faced with a huge problem. Communities across the country are struggling to meet the demands of growth and age on their facilities while at the same time feeling the political and public pressure to reduce costs and stabilize rates. As more communities focus on the need to improve their competitive position, they will turn to options such as internal re-engineering, privatization, managed competition, PPPs, and other alternative
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approaches to achieve their goals. Those that embrace the competitive environment and learn to respond creatively to its challenges are likely to be the real winners in the next millennium. (Dysard 2001, p. 90)
WATER SYSTEM SECURITY CHALLENGES On June 12, 2002, President George W. Bush signed into law the Public Health and Bioterrorism Preparedness and Response Act. Title IV of this Act amended the Safe Drinking Water Act to require that every water system serving more than 3300 customers conduct a assessment to determine its vulnerability to terrorist activity. In addition to the assessment, each qualifying water utility must prepare an emergency response plan that reflects the results of the assessment. The EPA made grants of up to $115 000 available to help utilities pay for their assessments (Landers 2002). Water utility response must include plans and procedures for responding to attacks on the system and lists of all equipment that can be used in the event of a terrorist attack or other security threats on the public water system. The State of New Mexico prepared the following list of what public water utilities can do immediately to guard against terrorist and other security threats to their systems (New Mexico Environment Dept. 2003): 1.
To guard against unplanned intrusion of utility facilities: ● Lock all doors and set alarms. Increase security at treatment plants. ● Limit access to facilities and control access to reservoirs. ● Secure hatches, meter boxes, and other access points to the distribution system. Control access to computer networks. ● Increase lighting in parking lots, treatment bays and areas with limited staffing. ● Never leave keys on equipment or vehicles. ● Ensure disinfectant (e.g., chlorine) is available at all times.
2.
To make security a priority for all employees: ● Upgrade hiring practices; know your employees. ● Develop a security plan and program; train employees in their use. ● Ensure communications protocols with local law enforcement, public health, environmental protection, and emergency response groups. Train customer service staff how to handle a threat call. ● Establish neighborhood watch groups.
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3.
To coordinate actions for effective emergency response: ● Review and update existing emergency response plans. ● Develop close relationships with local law enforcement groups. ● Establish clear chain-of-command for responding to threats. ● Report any customer illness that might be associated with water supplies; investigate all customer complaints. ● Report threats and suspicious behavior immediately.
4.
To improve security and infrastructure: ● Assess the vulnerability of source water areas, treatment plants, distribution networks, and other system components. ● Move as quickly as possible with the most obvious and costeffective physical improvements, such as tamper-proof manhole covers, fire hydrants, and valve boxes.
It is important to note that not everyone shares the level of fear regarding potential terrorist threat to the U.S. water supply. Berinato (2002) described a visit to a Massachusetts operations center during a test to determine whether the threat of cyberterrorism after 9/11 should be considered ‘real,’ or whether it was ‘simple fear mongering.’ After learning about the water system computer controls, many disinfection checks and balances extending throughout the systems, security codes, and distinctive system characteristics, Berinato concluded that the later argument was more likely to be true.
SUMMARY The early water systems in the U.S. were developed because existing town and private wells where most people drew their water were either (1) inadequate to meet the needs of a growing population, (2) subject to periodic pollution and carriers of many water-borne fatal diseases, or (3) unable to supply enough water for fire suppression, or for all three reasons. Unlike the few very large companies that dominated the telecommunications and energy utility industries, the water industry has largely remained in the hands of single-city municipal systems or a few relatively small companies (Crew and Kleindorfer 1986). Recently, however, a wave of consolidations has resulted in a number of horizontally integrated, often global, giants emerging in the industry. Most of the organizations that together make up the water industry may be grouped into the following six categories: Municipal water suppliers, agricultural water suppliers, federal agencies, state water agencies and projects,
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municipal wastewater collection and treatment agencies, and private and public toxic treatment organizations. A seventh type, private contractors, is becoming increasingly important in the industry. In the early 1800s, nearly all city dwellers drew their own water from public wells or from wagons that delivered water to individual customers. Periodic outbreaks of illnesses and water shortages led to the development of a few private water systems. Criticism of their exorbitant rates and service only to commercial and the more wealthy parts of town resulted in some cities taking control of the systems from private interests. The EPA classifies water systems into three categories by ownership: public, private, and ‘ancillary.’ Ancillary systems are small systems that provide water to a business; they serve less than 1 percent of the total population; private systems serve 13 percent; and public systems serve 86 percent of the U.S. population. Most U.S. wastewater systems are municipally owned. In 1996, there were 16 024 municipal treatment systems and 20 670 municipal collection systems in the country. Together, these treatment and collection systems served nearly 72 percent of the total population. A number of different types of organizations have evolved to develop and manage irrigation systems. After the Civil War, new organizations evolved to supply water. As settlers moved farther from water sources, land promoters sometimes formed companies to bring water from distant sources. Mutual water companies have replaced most of the earlier suppliers of water for agricultural purposes. Nearly 85 percent of all irrigation water organizations in the Western states are mutual water companies; they supply water to something like 20 percent of all irrigated acreage and some communities. The Clean Water Act of 1972 and the Safe Drinking Water Act of 1974 are the principal federal legislation governing the provision of safe drinking water in the United States. The CWA established rules regulating the discharge of pollutants. The CWA was passed after the public was made aware that the nation’s rivers and lakes were becoming polluted; many wetlands were drying up, and other irreplaceable wetlands were disappearing under real estate developments.
ADDITIONAL READING Glennon, Robert (2002), Water Follies: Groundwater Pumping and the Fate of America’s Fresh Waters, Washington, DC: Island Press. Lauer, William C. (ed.) (2001), Excellence in Action: Water Utility Management in the 21st Century, Washington, DC: American Water Works Association. Seidenstat, Paul, Michael Nadol and Simon Hakim (2000), America’s Water and Wastewater Industries, Washington, DC: Public Utilities Reports.
16.
Future challenges facing utility industry managers
The public utility industry is in the midst of one of the most trying periods it has faced since the Great Depression of the 1930s. Some of the key issues facing all segments of the industry include (1) the threat of terrorist attacks that could occur at any time and any place in the utility infrastructure; (2) rising operating costs with declining resource supplies; (3) increased demands for environmentally safe operations; and (4) industry restructuring that has brought about the unbundling of vertically integrated businesses. Investor-owned utilities have had to shift from the system of safe and secure regulatory control with ‘guaranteed’ returns on investment that has existed since 1935. While most have embraced the return to market pricing and global competition, others have found the transition fraught with difficulty. For an example of the problems facing the industry today, one need only review the failures, bankruptcies, and retrenchments in the industry that came about as a result of the problems in California in 2000 and 2001. For publicly owned utilities, the list of challenges also includes the drive toward smaller and more responsive government and competing needs for critical capital. This sector of the utility industry has seen privatization of large segments of municipal energy and water organizations. These trends have resulted in the outsourcing of many former public functions. Outsourcing is changing the very nature and rationale behind publicly owned utilities. Much of the infrastructure in both the publicly owned and investorowned sectors of the utility industry suffers from some degree of aging, inefficient, and/or obsolescent physical plants. Many old facilities have reached the end of their useful life and must be replaced. At the same time, the managers of these utilities are required by law to expand either one or more of their production, generating, transmission, and distribution networks to meet demand. In an attempt to regain control of escalating costs and shrinking capacity, utilities are embracing information technology as a tool to improve operations and return to profitability. For example, until recently, utilities were able to carry out real-time consumption metering for only a few of 269
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their largest customers. For the majority of their customers, meter readers came by once a month; they recorded the numbers showing on the meter and subtracted last month’s reading from the current reading. The utility sent the customers a bill in the mail. Customers wrote a check for the amount, and the cycle was repeated the following month. Advances in Internet-based communications technology have made it possible to change this pattern. These changes are making it possible for utilities to employ demand-based metering technology, in which customers are alerted in advance of price increases brought on by excessive demand on the system. Customers will have the choice of paying extra or of changing their usage patterns. Internet-based systems are expensive, however, and smaller utilities may have to decide whether to invest in technology upgrades or to invest in other new infrastructure.
KEY ISSUES IN THE ENERGY INDUSTRY Writing at the beginning of the last decade of the twentieth century, British economist T.W. Berrie examined the issues and options facing the global energy sector and found the rate of change taking place in the industry to be ‘accelerating and widening’ in scope. Berrie (1992) concluded that five urgent issues would constitute the greatest challenge to utility managers over the next decade. Events have shown that these challenges have had, and continue to have, a decisive impact on the industry. The issues and options identified by Berrie include: 1.
2.
3.
4.
Whatever form of ownership eventually is dominant (i.e., investorowned, publicly owned, or some combination of the two), the entire industry must identify enough reasonably priced money to maintain all the key sectors in good shape technically, operationally, managerially, economically, and financially. An optimum balance must be found between the interests and goals of legislative bodies, local authorities, state and federal regulators, the utility segments (generators, transmission organizations, distributors, and marketing groups), consumers, and the general public. Regardless of the form of ownership, electricity markets must become more efficient. This may take place through competition (wholesale, retail, or both), dynamic or real-time pricing, futures electricity markets, agents, and brokers. Managers must ensure that industry decision makers maintain proper concern for other sectors in the economy, especially rival sectors such as coal, gas, oil, wind, and other renewable producers.
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The nuclear power issue must be resolved. With the rapidly dwindling supplies and resultant heavy price increases for natural gas, decision makers must look toward other means of adding new electricity generating capacity. Despite the controversial nature of nuclear generators, the heavy environmental costs associated with coal-fired plants are causing many utilities to take another look at this source of power.
In one form or another, these are among the key issues concerning managers in the electricity, natural gas, and water and wastewater industries. Structural Changes in the Industry The nature of the power industry is undergoing a change in structure that is as encompassing as those that occurred during the 1930s. One result of the 2003 Northeast blackout has some observers asking to what extent fragmentation of the industry may have undermined the integrity and strength of the North American power system (Connor 2004). Two of the structural changes taking place at this time are (1) an overall consolidation of the industry and (2) a re-valuation for rate-base purposes occurring in portions of the industry. Rate-base changes have been made necessary by federally mandated restructuring, which in turn, has raised the issue of how to deal with stranded costs of earlier plant construction. Mergers and acquisitions are seen as a way to continue to grow in the investor-owned public utility sector, while at the same time adding longterm shareholder value.
KEY ISSUES IN ELECTRICITY While moving ahead with stalled restructuring remains an ongoing question, replacing, improving, and upgrading aging and inefficient generating, transmitting, and distributing infrastructure may be of even more importance today. Every sector is faced with the need to add capacity to meet rapidly growing demand. The rising costs of natural gas as fuel for power generators has again brought to the fore debate on whether to return to coal or to nuclear power for the needed new generating capacity. Rolling blackouts in 2001 in California and the 2003 blackout in large sections of the Northeast U.S. and Canada highlighted the need for better control of the existing transmission infrastructure while also accelerating planning for new capacity. The FERC’s program of bringing all transmission lines under control of independent regional transmission organizations
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has stalled along with other restructuring and deregulation efforts. One industry consultant described the situation in the following way: Much water has gone over the dam since the onset of electric power deregulation, and some of the good intentions that spawned the movement may have been washed out to sea. One of the results is the inability of the marketplace to demonstrate that the cost of delivered power to end users has been minimized at an acceptable level of reliability. The necessary institutional and regulatory frameworks for allowing the creation of optimal markets or true competition are still incomplete or counterproductive. Thus, our electric power infrastructure is a proverbial ship floating on the storm-tossed ocean, in danger of sinking beneath the waves. (Felak 2004)
Felak also called for North American electricity systems to be planned and operated with open and competitive access to the transmission grid in order for all resources to be able to optimally serve all power customers. Although they were emphasizing problems with the power system in Europe, Finon et al. (2004) raised many points that are also applicable in North America. One is that there appears to be a general underinvestment in the expansion of capacity that seems to follow the widespread movement to a deregulated economic environment. That perceived underinvestment has brought to light a need for stronger grid interconnections, particularly between regions with complementary resources or supply and demand patterns. Public Sector Issues In the public sector, outsourcing and privatization are also major issues facing electric utility managers. Municipal owners are strapped for the cash needed to bring their aging infrastructures up to modern standards. Following the lead of the water industry, a growing number of municipal utilities are signing long-term system operating contracts with private businesses. The contractors then agree to (1) pay an up-front fee to the city for the contract, (2) pay annual payments in shared revenues, and (3) invest in improvements needed to maintain and expand the system. According to Ruth (1999), this often enables the city or other government jurisdiction to trim its annual operating costs while at the same time improving the quality of the services it provides. The Impact of Gas Shortages on Electricity Generation Natural gas was in plentiful supply during the 1990s, and prices were generally low and stable. Natural gas was available at less than $2 per million British thermal units (Btu); in 2004, the cost was nearer to $6 per million
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Btu. Many large and small generating firms began installing low-cost, lowemission, gas-fired turbines for both primary and back-up generating capacity. A relatively inexpensive gas turbine generator could be installed and be running in close to two years, as compared to the seven to ten years required to get a coal-fired generating plant on line. No new nuclear plants have been constructed in the United States since the 1970s. However, nuclear power may not be the dead issue it was once thought to be. A variety of shifting conditions has altered peoples’ attitudes regarding nuclear power which, in turn, has lowered the level of public protest over this form of power generation. Together, these changed conditions make the idea of new nuclear power plant construction in the United States far more likely to occur – and to do so in the near rather than distant future. This new, more favorable environment for nuclear power was discussed in the lead article in the January 31, 2005 issue of Forbes magazine: The U.S. nuclear construction industry was presumed dead. It is anything but. If oil prices stay high, if people worry about carbon dioxide causing global warming, if the Middle East stays violent, nuclear power stands a good change of making a huge comeback in this century. . . . Over the past five years fans of atomic power have quietly lined up the support of federal and municipal governments and have cozied up to General Electric and Westinghouse Electric (now part of the British BNFL Group) in service to an ambitious agenda: building perhaps five new reactors by 2015, a dozen by 2020, and 50 by the mid-century. (Helman et al., p. 86)
Equally, there were few hydropower plant locations left to exploit in North America, and alternative, renewable sources such as wind, solar, and thermal production offered only minor additions to generating capacity. By 2002, gas-turbine generators made up almost all of the nation’s new generating capacity. Even though most new electricity generators are now fueled by natural gas, the majority of power generated in the U.S. is still produced by coal and nuclear generating facilities. Fully 50 percent of electricity was still generated by burning coal, 20 percent was generated by nuclear-powered generators, 19 percent by natural gas, 7 percent by hydroelectric facilities, and 4 percent from other sources. The price of natural gas has roughly tripled since the beginning of the new century. At the price of more than $6 per million Btu in the 2004 market, some utilities are now paying more for the gas to generate power than they can charge for the electricity they produce. As environmental regulations continue to become more restrictive, many of the coal plants now on line will be forced to install extensive and costly emission control devices. This is likely to cause some of the oldest and dirtiest coal plants to be retired. Box 16.1 is from a 2004 article describing developments in this sector of the industry.
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BOX 16.1
COAL MAKES A COMEBACK
Many of the nation’s utilities are retreating to an earlier technology as a way out of this dilemma. Nearly 100 new coal-fired electric power generating plants are planned in 36 states. If all are completed, they would add something like 62-gigawatts of low-cost electricity to the nation’s generating capacity. Illinois leads the rush to coal with a total of ten new generating plants proposed. The retreat to coal is seen as the only way to keep electricity prices low while also adding to energy security by offering an alternative to foreign oil and gas. Coal already produces about half of all the electricity generated in the country. However, coal-fired generators also pump into the air mercury and greenhouse gases such as carbon dioxide, nitrogen oxide, and sulfur dioxide. The new plants are estimated to add roughly one-tenth of 1 percent to the world’s annual carbon-dioxide emissions. Environmental groups have filed suit to stop new construction. The United States, with more than 250 years worth of coal reserves, has been called the ‘Saudi Arabia of coal.’ Source:
Mark Clayton, 2004, ‘The Coal Rush,’ Seattle Times, (February 27) A3.
The recent shortages and spike in the price of natural gas has forced some utilities to begin designing and/or building new coal-fired generators. However, if coal is to retain its dominant role in generation, a permanent resolution of environmental concerns associated with this fuel must be resolved. The Nuclear Power Challenge What to do about nuclear generation remains one of the most problematic issues facing managers in the electric power industry. As of 2004, there were 104 nuclear power plants operating in the U.S. although no new plants have come on line since 1979. Globally, the cost of building new nuclear generating plants has risen substantially. One of the reasons behind the rapidly accelerating costs and construction delays has been lack of coordination among the various sectors of the nuclear industry. It has been more than 30 years since the last license application was filed. However, despite the advanced age of some of these facilities, significant improvements in performance have taken place. According to the DOE,
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this increased performance, coupled with rising costs of fossil fuels and concerns about the contribution of fossil fuels to air pollution and global warming, has caused a renewal of interest in building new nuclear power plants (EIA 2004a). As of 2004, four new nuclear units were under construction in Asia. A number of industry participants were also examining the possibility of one or more new facilities in North America. Even if approval to build a new nuclear generating plant is granted, a new North American facility could not come on line until something like 2015. Nuclear Generator Requirements Four different types of organizations are necessary to bring a nuclear power generator on-line: (1) a construction management organization, (2) an organization or group that provides engineering and architectural design services, (3) a firm that supplies the reactor (the Nuclear Steam Supply System), and (4) the utility industry participant that purchases and operates the facility. Close coordination of all parties, including complete inclusion of all costs, is necessary if construction estimates are to be realistic and construction delays avoided. The costs of building nuclear generating facilities skyrocketed in the last decade. At the same time, the length of time needed to build a plant (lead time) grew from an average of eight years to more than ten years. From costs in the range of $1500 per kilowatt for facilities begun in the 1960s, construction costs grew to more than $4000 per kilowatt for construction started in the late 1970s. These costly difficulties were brought on by a number of different reasons, some of which were: ●
● ● ● ●
Increased regulatory requirements that caused design changes for plants during construction; Difficulties securing licenses to operate; Problems in managing very large projects; Errors in estimating benefits of economies of scale; Errors in estimating the need for additional capacity.
By 2004, most if not all of these difficulties had been successfully addressed by the industry. Today, the Energy Information Administration (EIA) estimates that construction costs of new technology (Generation III) nuclear generating facilities have dropped and now stand at $1400 to $1600 per kilowatt for large, single-unit plants; costs for two-unit plants are estimated to cost from $1210 to $1365 per kilowatt. Follow-on, two-unit plants would cost even less, possibly no more than $1040 per kilowatt.
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The Hydroelectric Generating Challenge The overwhelming majority of the hydroelectric generation capacity in North America is in the hands of federal operators. In the U.S., most of these facilities generate power for consumers in the western half of the nation. The most important exception to this rule is the Tennessee Valley Authority (TVA), which has been supplying power to the Southeastern U.S. since the first dam and power plant were completed in 1925. The TVA public corporation was organized in 1933 and ordered to plan for the proper use, conservation, and development of the natural resources of the 42 000 square-mile Tennessee River watershed. Similar development of the Pacific Northwest’s Columbia River Basin began in 1933. The first Columbia River project was the Bonneville Dam, some 42 miles east of Portland, Oregon. Construction of the Grand Coulee Dam near Spokane, Washington, was started in 1934 as a relief program and completed in 1942. The Grand Coulee was built for three purposes: power generation, irrigation, and water transportation. The Bonneville Power Administration (BPA) was established in 1940 to manage the system and market the power generated by the Columbia River dams. BPA functioned as planned until the closing days of the last century, when power shortages caused brownouts and price spikes on the West Coast. BPA was mandated by Congress to provide power on a preferential basis to publicly owned utilities. Earlier, the legislatures of Oregon and Washington had authorized the formation of Public Utility Districts (PUDs). As preferred customers, these mostly rural PUDs served as an outlet for the cheap hydroelectric power generated by BPA. By the 1990s, a number of large utilities and industrial customers (primarily aluminum smelters) had turned to cheaper sources of power on the wholesale market and chose to opt out of their contracts with BPA (Burr 2004b). When the power shortages hit in 2000 and 2001, many of those customers returned to BPA. Because of their federally mandated preference status, BPA was legally required to once again accept them as customers. Contracts were signed that increased demand by 3000 megawatts – exceeding the generating capacity of BPA by some 30 percent. The agency was forced to purchase power from other sources in order to meet its obligations. This resulted in a 46 percent rate increase across all customers. A number of additional environmental constraints were contributing to BPA’s woes at this time. One is the basic issue of preferential customers. Investor-owned utilities have lobbied to have the preference clause removed so that they can have equal access to BPA power. In addition, Bonneville has voluntarily agreed to unbundle itself by splitting off its extensive transmission system as an independent regional transmission organization
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(RTO), which is to be called Grid West. Other issues include persistent drought conditions in the region, endangered fish populations, and a huge budget shortfall. Climate changes may pose the greatest threat to the system, however. In the latest computer climate model issued in February of 2004, the Department of Energy’s best-case scenario predicted a 70 percent decline in the coastal mountain snowpack over the next 50 years. This is likely to result in significant reductions in hydropower production in spring and summer months. Policymakers and utility managers are increasingly looking to wind power and conservation as ways to address the expected shortages. These and other issues are having similar impact on much of the federal hydropower system. What is Needed to Revive the Electricity Sector In August of 2003, the independent, nonprofit National Commission on Energy Policy issued an analysis of what it perceives to be the major challenges facing the electricity industry (NCEP 2003). Portions of that report are included here to provide a blueprint for the tasks utility managers must deal with during the first decades of the twenty-first century. The commission closed its study with a dozen recommendations that the various sectors of the industry can take now to get the ‘derailed’ industry back on track. First among the many challenges the Commission identified was the breakdown in the Federal Energy Regulatory Commission’s (FERC) efforts to promote efficient, effective wholesale and retail competition. The implementation of competition has been impeded by (1) conflict among the states and the federal regulatory agencies, (2) regulatory and legislative uncertainty, (3) illegal and immoral behavior, (4) poor credit, and (5) company collapse, of which Enron was only one of the most notable examples. The FERC’s attempt to develop more efficient markets through RTOs has resulted in confusion and opposition in much of the country. The use of natural gas to generate electricity, which once held such promise, now appears to be a two-edged sword. On one side, the last five years has seen the addition of more than 100 000 megawatts of relatively clean, low cost, gas-fired peak and base load capacity. On the other side, however, many areas now face high and unstable prices for natural gas, with no break on the horizon. Another significant challenge is that investment in all categories of electricity infrastructure has declined significantly. Investment is expected to continue to be below normal until FERC clarifies how the costs will be recovered and who will reap the financial reward for making the investments. Individual states vary greatly in their willingness to introduce retail
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electricity competition. In states that have done so, many retail customers have been unwilling to switch in the absence of any significant cost savings. Efforts to expand retail competition are on hold in nearly all those states that had earlier signaled a willingness to give competition a try. Retail marketers of electricity have lost billions without producing a reliable and profitable product. Confusion still reigns in the industry over who is responsible for putting together a diversified mix of short- and long-term power commitments and other risk management tools. Many of the firms that were active early in attempting to develop a viable electricity futures market have exited the market after suffering huge losses. The fear of being stuck with unrecoverable, stranded costs has driven many potential investors away from additional investments in electricity industry securities. The electricity industry has, and will continue to have for a long while, a tremendous impact upon the environment. The industry must deal with many different technologies and a variety of different regulatory agencies and other stakeholders. These only add to the uncertainty that managers in this industry face. Finally, the entire system remains highly vulnerable to terrorist attack; protecting the industry will require significant government and private sector cooperation. The Energy Policy Commission released a number of ‘prototype’ recommendations for dealing with the challenges identified in its preliminary report (more detailed recommendations were to be released at a later date). As used in these recommendations, the term ‘portfolio manager’ refers to the assembler of a diversified mix of short- and long-term power commitments and other risk management tools needed to sustain economical and reliable electricity services. This may be any one or a group of participants in the supply chain, including power generation, transmission, and/or distribution organizations. The Commission’s recommendations were grouped according to their applicability for four groups of stakeholders as follows: For State Regulators and Directors of Consumer-owned Utilities: 1.
The retail distribution of electricity for residential and small business customers should continue to be the responsibility of utilities regulated by state and local jurisdictions. If any customer elects to opt out of regulated service, they should be allowed to return only on terms that hold harmless other customers and the portfolio manager. Small customers in states that allow retail competition should be permitted the opportunity to choose alternative suppliers at least once every five years.
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3.
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Large customers selecting regulated service should be required to sign long-term contracts with the portfolio manager. Customers not opting for regulated service should make their own way in competitive retail markets. Regulators and boards of consumer-owned utilities should focus on incentives for good portfolio management. This includes systems of performance-based regulation based on objective benchmarks and incentives for managers. Regulated portfolio managers should be held accountable but also not subjected to arbitrary, complex regulatory review processes.
For the Federal Energy Regulatory Commission: 4.
5.
Although supporting the FERC’s efforts to maintain nondiscriminatory transmission access to grids and wholesale markets, the Commission also recommends that the needs of states that have not adopted retail competition be considered. Moreover, the Commission urges that the FERC also consider the states’ role in ensuring reliable supplies. Congress should authorize application of these requirements to all transmission systems, regardless of their owners. The national electricity system must establish dispersed and wellguarded stockpiles of the critical equipment with long manufacturing lead times. In addition, such equipment should be standardized wherever possible. These steps are necessary to maintain system security and reliability. Particular attention should be paid to maintaining the security of Supervisory Control and Data Acquisition systems.
For Congress: 6.
7. 8.
Both society and the power generation sector of the industry will benefit from greater certainty and coordination over federal targets and timetables for long-term environmental objectives. Congress should develop an integrated regulator structure that sets a firm, multi-year schedule of phased emission reductions that considers both the environments and system reliability. In addition, marketbased mechanism should be used as much as possible to minimize the cost of compliance while encouraging innovation. Congress should tighten energy efficiency standards wherever costeffective and practicable. The August 2003 blackout in the Northeast was a reminder that the voluntary system of compliance with reliability rules for electricity grids is no longer sufficient. Congress should approve new, widely
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supported plans to make the rules mandatory and enforceable, with ultimate oversight responsibility remaining in the hands of the Federal Energy Regulatory Commission. For All Decision Makers: 9.
10.
11.
12.
Greater transparency for spot market prices and volumes of electricity trading, with real-time reporting, are urgent priorities. Wholesale markets for real time, day ahead, and long-term sales work best when they are liquid and transparent. The inadequate investment in transmission infrastructure is a significant and growing national problem. No single solution is adequate; new technologies and new ideas are needed. FERC should also clarify who is responsible for identifying and making investments in new transmission lines. Congress, FERC, and state regulators should push for greater interconnection of electricity systems and to encourage more planning for regional resource and grid enhancement. Finally, there is an urgent need to revive research and development in the electricity industry. R&D is down by more than three-fourths over the last two decades. The Commission recommends federal tax incentives and state-approved utility investments, with costs recovered by small charges on electricity distribution.
FERC Plans, Goals, and Key Initiatives In its 2002–07 strategic plan, the FERC included four major goals that address most of the policy recommendations of the National Commission on Energy Policy. Each goal incorporates a number of key initiatives that the Regulatory Commission hopes to accomplish. The goals and a sample of program initiatives are as follows: Goal 1: To promote a secure, high-quality, environmentally responsible infrastructure through consistent policies. Key initiatives involved energy infrastructure programs, generation interconnections, and revamping hydroelectric license rulemaking. Goal 2: To foster nationwide competitive energy markets as a substitute for traditional regulation. Key initiatives include completion of the standard market design, and formation of a regional transmission organization system. Goal 3: To protect customers and market participants through vigilant and fair oversight of the transitioning energy markets. Key initiatives
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involve market oversight, and alternative dispute resolution procedures for handling complaints. Goal 4: To strategically manage agency resources. Key initiatives include development of online FERC programs, the e-library, and completion of a performance measurement system.
KEY ISSUES IN NATURAL GAS One of the biggest challenges facing the natural gas industry is securing a long-term, steady, secure, affordable supply of natural gas for all users. Gas has become a major commodity in the residential, industrial, and powergenerating markets. Because it has been a relatively inexpensive, clean burning fuel with high thermal efficiency, the U.S. has adopted natural gas as the preferred fuel for new power generators. This greater than normal growth in the demand for natural gas began with the drive for energy selfsufficiency that followed the oil shocks of the 1970s. Natural gas use in the U.S. is expected to grow from the 22.14 trillion cubic feet per year (tcf) consumed in 2004 to 25.1 tcf in 2010 and 30.90 tcf per year by 2025. In 2004, the industrial sector consumed the largest proportion, 7.41 tcf, followed by the electrical power generation sector (5.30 tcf). The relative importance of these two sectors is expected to reverse by 2025, when the electricity generation sector is projected to consume 9.44 tcf, with industrial sector use projected at 9.13 tcf. Other consumption by sectors is displayed in Table 16.1(U.S. Dept. of Energy 2005). Demand by electricity generators is projected to increase moderately from 27 percent of the total in 2002 to 29 percent of total end-use in 2025. The greatest percentage increase will occur in the industrial sector, where Table 16.1 Projected increases in natural gas use in the U.S., 2004–25 (trillion cubic feet per year) Consumption by sector
2004
2025
Electricity generation Industrial Residential Commercial Transportation Other Totals
5.25 7.07 4.96 3.09 0.03 1.78 22.14
9.44 9.13 5.99 4.11 0.11 2.12 30.90
Source: U.S. Department of Energy. Natural Gas Supply and Disposition, 2005.
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demand will increase from 7.3 trillion tcf in 2002 to 8.4 tcf in 2010, and to 10.3 tcf in 2025. Demand in the residential sector is projected to only increase by less than 1 percent (0.9), while demand in the commercial sector will grow by just 1.1 percent from 2002 to 2025 (EIA, June 2004b). Despite the decline in proven gas reserves, production in domestic natural gas is expected to increase over the next several decades. According to the Department of Energy (EIA 2004a), much of this increase will come from unconventional sources. Unconventional sources include tight sands (also known as low-permeability sandstone), shale, and coalbed methane. Of the 18.6 trillion cubic feet of natural gas produced in 2002 in the contiguous 48 states (excluding Alaska and Hawaii), 42 percent was from conventional onshore sources; 32 percent was from unconventional sources; and 26 percent was from offshore sources. By 2025, total 48-state U.S. production is expected to increase to 21.3 tcf; 43 percent – 9.2 trillion cubic feet – of this total is projected to come from unconventional sources. Proven reserves of coalbed methane and tight sands are highest in the U.S. Rocky Mountain region, while reserves of shale beds are highest in the Northeast. Canada has been the primary source of natural gas imports to the United States. However, production in older Canadian fields is declining, while domestic demand in Canada is growing. Imports of liquefied natural gas (LNG) are expected to replace lost Canadian imports; by 2015, LNG imports are expected to be greater than imports from Canada. U.S. imports of LNG doubled from 2002 to 2003, with strong growth expected to continue over the long-term. Four new import terminals are expected to open on the Atlantic and Gulf Coasts between 2007 and 2010, nearly doubling the total. In 2004 there were four terminals in operation in the same region, with a fifth terminal in Puerto Rico and a sixth terminal in Alaska, from which LNG is processed and shipped to Japan. As of December 1, 2003, the Department of Energy reported another 32 active proposals for new terminals: eight for the West Coast of California or Mexico, three for Florida or the Bahamas, 14 for the Gulf Coast, and seven for the East Coast of the U.S. or Canada. The U.S. natural gas industry is expected to remain subject to extensive regulation by federal, state, and local agencies (Calpine 2002). The challenge for utility managers is determining how to adjust their operations to comply with the many different and often contradictory agency regulations. Each agency has its own remedies that can be used to enforce federal, state, and local rules, regulations, and procedures. These include fines, penalties, revocation of permits and licenses, actions affecting the value of assets, and outright suspension of production. Some of the environmental regulations
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with greatest impact on the industry at this time are discussed in the next section. Environmental Challenges Numerous federal, state, and local regulations have been adopted to protect the environment, to control air and water pollution, and to regulate various segments of the utility industry. These regulations cover the exploration for and development of geothermal resources and oil, gas liquids, and natural gas supplies. Other regulations cover the construction and operation of wells, fields, pipelines, various other mid-stream facilities and equipment, and power generating facilities and transmission lines. Still other regulations limit the discharge of emissions into the air and water. They also include wetlands preservation, protection of endangered species, hazardous materials handling and disposal, waste disposal, and noise regulations. These laws and regulations typically require long and complex processes for securing construction and operating licenses, permits, and other approvals. Noncompliance of a single rule can be exceedingly costly and may result in loss of permission to operate. Some of the laws of particular concern to utilities include the Federal Clean Air Act of 1970, the Clean Water Act, the Oil Pollution Act of 1990, the Safe Drinking Water Act, the Resource Conservation and Recovery Act, and the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. In addition to these specific issues, the fundamental approach to national environmental policy in general is also changing. Utility managers must keep pace with the institutional realignments – restructuring, downsizing, outsourcing, and privatization – that are causing major upheaval in the scope and structure of the industry. At the same time, the role of government is narrowing, with many services now paid for by user fees or provided by private-sector contractors. As a result, the private sector is being reshaped by a broadening of responsibilities. Moreover, nongovernmental organizations, many of which are taking on the role of external service contractors, are becoming important policy shapers (Chertow and Esty 1997). Reduction of Greenhouse Gases In February of 2002, the federal government announced the President’s Global Climate Change Initiative, which is a program to reduce U.S. greenhouse gas intensity (GGI) by 18 percent by 2012. ‘Greenhouse gas intensity’ was defined as a ratio of total U.S. greenhouse gas emissions to economic output (EIA 2004a). GGI is measured in thousand metric tons of carbon
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dioxide equivalent per billion 1996 dollars of gross domestic product. Carbon dioxide is the greatest contributor to greenhouse gas, representing nearly 83 percent of total greenhouse gas emissions in 2002. Carbon dioxide is created with the burning of fossil fuels. Shifting to natural gas from the use of coal for power generation was seen as a major step toward achieving the objective of reducing carbon dioxide emissions. However, the decline in gas supplies, increased demand for gas for other uses, and resulting rising prices have caused the industry to take another look at more traditional fuel sources, including coal and nuclear. In 1990, passage of the Clean Air Act Amendments reduced the allowable levels of emissions of sulfur dioxide and nitrogen oxides. This triggered even greater growth in the adoption of natural gas as the fuel of choice for electricity generators, while also hastening the demise of older coal-fired facilities. The Clean Air Amendments bill also identified mercury emissions as a toxic air pollutant; the Environmental Protection Agency (EPA) estimated that 32.7 percent of all U.S. mercury emissions come from coal-fired power plants (Shere 2004). In 2003, the EPA proposed new rules on mercury, sulfur dioxide, and nitrogen oxides emissions. Ten states and 45 senators petitioned the EPA in April of 2004 to drop its proposals because the restrictions were not strict enough. Noting that any rule change could not go into effect before 2005 or 2006, the states of Massachusetts, New Hampshire, Oregon, and New York’s Suffolk County have already implemented their own mandatory reductions in greenhouse gas emissions by power plants. Connecticut has passed legislation restricting mercury emissions. Water utilities applaud these emissions restrictions for their contribution toward cleaning up water supplies as well as reducing air pollution. Finally, in late August of 2003, the EPA began a change of the rules and operating definitions pertaining to power generator ‘routine maintenance.’ The rules restrict upgrades of older, dirtier plants without also installing pollution control equipment, but do not include the threat of legal action for failure to comply. The changes were challenged in court by a coalition of 14 states and the District of Columbia.
KEY ISSUES IN WATER OPERATIONS Ten important trends facing the water and wastewater industry were identified in the American Water Works Association (AWWA) membership newsletter, E-Mainstream. These ‘megatrends’ were listed in a report on the results of a 2004 videoconference held to address current issues in
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water utility operations (AWWA 2004). They include the following crisis themes: 1.
A crisis of compliance More and more stringent regulations, including more identified contaminants, are forcing utilities to develop costly programs to deal with the increased complexity of compliance.
2.
A crisis of infrastructure There is a pressing need to add to and improve utility plant and facilities – estimated to cost in excess of $1 trillion by 2020.
3.
A crisis of finance Some rate payers are already paying 4 percent of their income for water, and utilities are continuing to raise rates.
4.
A crisis of supply Population growth, economic development, and increasing water use are resulting in growth in demand, even while resources remain limited. In many locations, several jurisdictions are competing for access to water resources.
5.
A crisis of confidence Public trust and confidence in public drinking water have been eroded by announcements of outbreaks of water-born diseases. Moreover, although consumers are willing to pay high prices for bottled water, they balk at high prices for public water supplies.
6.
A crisis of size Small water systems are unable to survive as independents. While some merge with other systems, others are forming various types of regional systems.
7.
A crisis of system structure Privatization, outsourcing, design-build-operated, and other approaches to alternative service providers is occurring regularly, as municipal systems seek ways to fund needed system operations and growth.
8.
A crisis of human resources Large numbers of skilled workers retiring over the next decade are changing the nature and character of the utility workforce. Diversity, recruiting, and retention challenges will loom large in the years ahead.
9.
A crisis of productivity The introduction of competition into what was often a regulated natural monopoly requires development of efficient and cost-effective support services.
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A crisis of technology The continued growth in the application of computer technology, greater application of automated systems, and other innovations are driving revisions in the business processes in utilities.
These trends could easily serve as strategic planning master topics for water and wastewater management personnel. Missing from the list of major management challenges was the security issue. Since September 11, 2001, the notion of terrorists’ attacks on American soil has become very real. Protecting the Nation’s Water Supply Protecting the country’s water supplies has become a leading concern of everyone in the water industry. Part C of the Safe Drinking Water Act requires the disposal of wastes such as saltwater, process water, and oil and gas production wastes, by means of deep well injection. However, deep well injection does not guarantee elimination of shallow well pollution; water travels upward as well as sideways and downward through porous underground aquifers. The majority of the nation’s drinking water is drawn from relatively shallow wells and may, as an indirect result of waste injection, be subject to potential contamination. The Public Health Security and Bioterrorism Preparedness and Response Act of 2002 required every community water system serving more than 3300 persons to conduct a vulnerability assessment of their complete operations (EPA 2004). Certified copies of these assessments were to be submitted to the EPA according to the following schedule: systems serving populations of 100 000 or more, March 31, 2003; systems serving populations from 50 000 to 99 999, by December 31, 2003; and systems serving populations from 3301 to 49 999 had until June 30, 2004, to submit their assessments. Utilities were required to submit certified copies of an ‘emergency response plan’ six months after submitting the vulnerability assessment. By the end of 2004, the Department of Homeland Security (DHS) planned to issue its national all-hazards plan to deal with terrorist and other security-related threats. A large portion of the DHS plan is devoted to water security issues. The purpose of the vulnerability assessment is to help water system managers evaluate their susceptibility to potential threats and identify corrective actions to reduce or eliminate the risk of unexpected actions. These range from simple vandalism to insider sabotage and external terrorist attacks. The assessment examines the vulnerability of the water supply,
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transmission, treatment, and distribution systems. EPA has suggested utilities consider the following common elements in their assessments: ●
●
●
●
● ●
Detailed description of the water system and its management organization, including its mission and objectives; Identification and prioritization of the negative consequences of a breach of security action; Determination of which critical assets are more susceptible to terrorist acts; Assessment of the likelihood of destructive acts from political adversaries; Identification and evaluation of existing countermeasures; Analysis of the current and long-term risks, together with a prioritized plan for reduction and elimination of risks from external and internal sources.
Problems with the Underground Water Supply Groundwater has become a critical source of drinking water in North America. In 2003, something like 48 percent of the total U.S. and Canadian population, and 95 percent of the rural population drew their water supply from wells (AWWA 2004). Overall, two-thirds of the groundwater withdrawals took place in the western United States. In 1995, states such as Florida, New Mexico, Mississippi and Hawaii, groundwater constituted in excess of 90 percent of all drinking water (Glennon 2004). The problem with groundwater pumping is that in many locations, depletion is far outpacing the ability of nature to recharge underground aquifers. Particularly vulnerable is the High Plains region of the U.S. This region includes portions of seven states. The Ogallala Aquifer underlies the region. Water from melting glaciers percolated into this aquifer from 10 000 to 25 000 years ago. Today, this region receives very little rainfall. As a result, there is almost no natural recharge of the aquifer. Water pumped out is not being replaced. Technology in the form of high-capacity, electric pumps have allowed farmers throughout the region to tap this supply for crop irrigation, making it a major region for the growing of such crops as alfalfa and wheat. Because of this pumping, by 1997 in some places the Ogallala water table has fallen more than 150 feet. Depletion continues unabated. Without some form of recharging the Ogallala, farmers in these states may soon find themselves returning to dry land farming techniques, and this is not the only region in the nation where groundwater pumping for irrigation has created major problems for the region. In parts of California’s
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central valley, for example, groundwater pumping has caused the land surface to drop more than 30 feet. In Southeast Arizona, groundwater pumping and destruction of natural habitat has caused the Santa Cruz River to disappear completely. In Florida, which takes nearly all of its drinking and agricultural water from underground sources, rivers and lakes have dried up, wetlands have disappeared, and huge sinkholes have appeared in the land.
SUMMARY The public utility industry is facing one of the most trying periods of its more than a century of service. Economist T.W. Berrie examined the issues and options facing the global energy sector and concluded that five urgent issues would constitute the greatest challenge to utility managers over the next decade: (1) acquire enough reasonably priced money to maintain all the key sectors in good shape technically, operationally, managerially, economically, and financially; (2) forge a balance between the interests and goals of legislative bodies, local authorities, regulators, utility industry segments, consumers, and the general public; (3) solve the inefficiency of electricity markets; (4) maintain proper concern for other sectors, especially coal, gas, oil, wind and other renewable producers; and (5) resolve the nuclear power debate. Because of the rapidly dwindling supplies and resultant heavy price increases for natural gas, decision makers must look toward other means of adding new electricity generating capacity. Nuclear generation of electricity is still not considered a viable option in the U.S. Although most coal-fired electrical generating facilities have significantly reduced the volume of pollutants they discharge into the air, by 2000 pressure from environmental groups had resulted in few if any utilities considering developing new coal plant construction. However, this changed dramatically after the power shortage problems occurred in California and other Western U.S. states during 2000–01. Utilities now see coal as far less a problem fuel than nuclear. As a result, in 2004 many new large coal-fired plants were planned or already under construction in the American Midwest, where large supplies of coal are available with relatively easy access in surface mining procedures. Among the big issues in the electricity industry are: moving ahead with stalled restructuring; replacing older generating, transmitting, and distributing facilities; the rising costs of natural gas and whether to turn to coal or nuclear power for the new generating capacity; and adding new technology.
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A major question facing the natural gas industry is securing a steady, secure, affordable supply of natural gas for all users. Gas has become an important commodity in the residential, industrial, and power-generating markets because it is a clean burning fuel with high thermal efficiency and, until recently, was relatively inexpensive. The industry and policymakers must also decide whether they will continue the drive toward wholesale and retail power, gas, and water competition, or retreat from the proposal. A reversal of restructuring is currently taking place in the electric power industry. Until recently, Canada was the primary source of natural gas imports to the United States. However, production in older Canadian fields is declining, while domestic demand in Canada is growing. Large proportions of the natural gas supply shortfall is expected to be taken up with imports of liquefied natural gas. Numerous federal, state, and local regulations have been adopted for the protection of the environment and to regulate land use by the energy industry. These regulations cover the exploration for and development of geothermal resources, oil, gas liquids, and natural gas. Ten important trends facing the water and wastewater industry were identified by the American Water Works Association. The Public Health Security and Bioterrorism Preparedness and Response Act of 2002 required every community water system serving more than 3300 persons to conduct a vulnerability assessment of their complete operations (EPA 2004) and a plan that spells out how they were going to resolve discrepancies in their preparedness.
ADDITIONAL READING Chertow, Marian R. and Daniel C. Esty (eds) (1997), Thinking Ecologically: The Next Generation of Environmental Policy, New Haven, CT: Yale University Press. Energy Information Administration (2004), Annual Energy Outlook: Issues in Focus, Washington, DC: Department of Energy. www.eia.doe.gov/oiaf/aeo/ download.html Glennon, Robert (2002), Water Follies: Groundwater Pumping and the Fate of America’s Fresh Waters, Washington, DC: Island Press. Institute for Energy, Law and Enterprise (2003), Introduction to LNG, Houston, TX: University of Houston Law Center. www.energy.uh.edu/LNG/documents/ IELE
Glossary and useful terms The following is a list of phrases, acronyms and terminology which frequently appear in the utilities industries and associated literature. A number of them, but not all, are used in this volume. It is provided to help the reader build on and extend the discussion in the text. (Sources: A majority of these terms and definitions were supplied by PowerMarkers.com and are used here with permission.) acid rain Acid rain is precipitation containing harmful amounts of nitric and sulfuric acids formed primarily by nitrogen oxides and sulfur oxides released into the atmosphere when fossil fuels are burned. acre-foot of water The amount of water needed to cover one acre of land to a depth of one foot (325 851 gallons). active solar energy Solar radiation used to provide space heating, water heating, or produce electricity. actual peak load reductions The actual reduction in annual peak load (measured in kilowatts) achieved by customers who participate in a utility demand-side management (DSM) program. It can be used as a measure of the effectiveness of the DSM program. aggregator An entity that negotiates the purchase of energy in bulk for a group of consumers, and tries to negotiate lower prices. The group of consumers is called a buying group. allowance for funds used during construction (AFUDC) An accounting noncash item indicating the estimated composite interest costs of debt and a return on equity funds used to finance utility plant construction. The allowance is capitalized in the property accounts and included in income. ampere The unit of measurement of electrical current produced in a circuit by one volt acting through a resistance of one ohm. ancillary services Additional services which are necessary to support the transmission of energy from resources to loads while maintaining reliable operation of the transmission provider’s transmission system. 291
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annual effects The total effects in energy use (measured in megawatt hours) and peak load (measured in kilowatts) caused by all participants in the DSM programs in effect during a given year. The annual effects considers the useful life of efficiency measures, by accounting for facility demolition, equipment degradation, and attrition. annual transmission costs The total annual cost of the transmission system. It is the amount specified in rate Schedule 1 until amended by the transmission provider or modified by the Federal Energy Regulatory Commission (FERC). anthracite A hard, black lustrous coal, often referred to as ‘hard coal,’ containing a high percentage of fixed carbon and a small percentage of volatile matter (mineral pollutants). Anthracite contains approximately 22 to 28 million BTU per ton. aquifer A geologic formation with enough saturated porous and permeable material to transmit water at a rate sufficient to feed a spring or well. ash Impurities consisting of silica, iron, alumina, and other noncombustible matter contained in coal. Ash increases the weight of coal, adds to the cost of handling, and can affect its burning characteristics. Ash content is measured as a percent by weight of coal on an ‘as received’ or moisturefree, laboratory tested, basis. asset An economic resource, tangible or intangible (such as a patent), which is expected to provide benefits to an organization. available but not needed capability Net capability of main generating units that are operable but not considered necessary to carry load, and cannot be connected to load within 30 minutes. average revenue per kilowatt hour The average revenue per kilowatt hour of electricity sold by sector (residential, commercial, industrial, or other) and geographic area. Area can be state, census division, or national. It is calculated by dividing the total monthly revenue by the corresponding total monthly sales for each sector and geographic unit. barrel A volume unit of measurement for crude oil and petroleum products that is equivalent to 42 US gallons. The abbreviation for barrel is ‘Bbl.’ base bill A charge calculated by multiplying the appropriate schedule rate by the level of consumption. baseload The minimum amount of electric power delivered or required over a given period of time at a steady rate. The lowest level of power needed during a time period (usually a season or a year).
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baseload plant The capacity of the generating equipment normally operated to serve loads on an around-the-clock basis. bcf The abbreviation for 1 billion cubic feet (commonly used for measuring amounts of natural gas). biomass Biomass is waste organic material that can be used as a fuel for electric generation. It includes such material as dead trees and branches, yard waste, left-over crops, wood chips, bark, and sawdust from lumber mills. It also includes combustible material found in household, commercial and industrial waste. bituminous coal The most common type of coal. It is dense and black, often with well-defined bands of bright material. Its moisture content is usually less than 20 percent. It is widely used for generating electricity, making coke, and for space heating. Sub-bituminous and bituminous coal contain from 16 to 24 million BTU per ton and from 19 to 30 million BTU per ton, respectively. Five categories of bituminous coal are recognized as determined on a dry mineral-matter-free (mmf) basis for fixed-carbon and volatile matter and a moist mmf basis for calorific value: (1) Low volatile bituminous coal; (2) Medium volatile bituminous coal; (3) High volatile A bituminous coal; (4) High volatile B bituminous coal; and (5) High volatile C bituminous coal. blackout A total power loss affecting many consumers over a large area for a significant period of time. British thermal unit (BTU) A standard unit for measuring the quantity of heat energy equal to the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. brownout A controlled power reduction in which voltage is decreased on power lines so customers receive weaker electric current. Brownouts are used when total power demand exceeds the maximum available capacity. bulk power voltages.
Large amounts of electrical energy transmitted at high
capability The maximum load that a generating unit, generation station, or other electrical apparatus can carry under specified conditions for a given period of time without exceeding approved limits of temperature and stress. capacity The amount of electric power delivered or required for which a generator, turbine, transformer, transmission circuit, station, or system is rated by the manufacturer.
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capacity (purchased) The amount of energy and capacity available for purchase from outside the system. capacity charge An element in a two-part pricing method used in capacity transactions (energy charge is the other element). Sometimes called the ‘demand charge,’ the capacity charge is assessed on the amount of capacity being purchased. capital (financial) The line items on the right side of a balance sheet. They include debt, preferred stock, and common equity. A net increase in assets must be financed by an increase in one or more forms of capital. census divisions The nine geographic divisions of the U.S. established by the Bureau of Census and used for statistical analyses. The boundaries coincide with state boundaries. The divisions may also be subdivided into smaller units. The Pacific Division, for example, is subdivided into the Pacific Contiguous and the Pacific Noncontiguous (Alaska and Hawaii) divisions. circuit A conductor or a system of conductors through which electricity flows. cogenerator A generating facility that produces electricity and another form of useful energy (such as heat or steam) that is used for industrial, commercial, heating, or cooling purposes. To be identified as a qualifying facility (QF), the facility must meet certain ownership, operating, and efficient criteria established by the FERC. coincidental demand The sum of two or more demands for energy that occur in the same time interval. coincidental peak load The sum of two or more peak loads that occur in the same time interval. combined cycle An electric generating technology in which electricity is produced from otherwise lost waste heat exiting from one or more gas combustion turbines. The exiting heat is routed to a conventional boiler or to a heat recovery steam generator for use by a steam turbine to produce electricity. The process increases the efficiency of the electric generating unit. combined cycle unit An electric generating unit consisting of one or more combustion turbines and one or more boilers with a portion of the required energy input to the boiler(s) provide by the exhaust gas of the combustion turbine(s). combined pumped-storage plant A pumped-storage hydroelectric power plant that uses both pumped water and natural stream flow to produce electricity.
Glossary and useful terms
295
commercial operation Commercial operation begins when control of the loading of the generator is turned over to the system dispatcher. commercial sector The commercial sector is defined as non-manufacturing business establishments, including hotels, motels, restaurants, wholesale firms, retail stores, and health, social, and educational institutions. commercial service Commercial service may be classified as demand or annual use that exceeds some specified limit, which may be set by the utility based on its rate schedule. Customers for commercial service are usually, but not have to be, organizations classified as belonging to the commercial sector. commission A public body with power to regulate or oversee the activities of one or more types of public utilities. Examples include the Federal Energy Regulatory Commission (FERC) or any local State Public Utility Commission (PUC). connection The physical connection (such as by transmission lines, pipelines, transforms, switch gear, etc.) between two utility systems permitting the transfer of product in one or both directions. conservation and other DSMs This demand-side management category represents the amount of consumer peak load reduction at the time of system peak due to programs that reduce consumer load. It also includes all other DSM activities, such as thermal storage, time-of-use rates, fuel substitutions, measurement and evaluation, and others designed to reduce demand and/use. construction work in progress (CWIP) The balance shown on a utility’s balance sheet for construction work not yet complete but in process. This line item may or may not be included in the rate base. consumption (fuel) The amount of fuel used for gross generation, providing standby service, start-up and/or flame stabilization (flame stabilization refers to the practice of keeping a small amount of fuel burning to ensure that heat is always ready to immediately be used for generating electricity). contract price The price of fuels marketed on a contract basis and covering a period of one or more years. Contract prices reflect market conditions at the time the contract was negotiated and therefore remain constant over the life of the contract, or are adjusted through inclusion of escalation clauses. Generally, contract prices do not fluctuate widely. contract receipts Purchases based on a negotiated agreement that generally covers a period of one or more years. control area An electric power system or combination of systems to which a common automatic control scheme is applied in order to: (1) match at all
296
Glossary and useful terms
times the power output of generators in the system(s) and capacity and energy purchased from sources outside the system(s) with the load in the system(s); (2) maintain, within the limits of good utility practice, scheduled interchange with other control areas; (3) maintain the frequency of the system(s) within reasonable limits in accordance with good utility practice; and (4) provide sufficient generating capacity to maintain operating reserves in accordance with good utility practice. conventional power Power produced from non-renewable fuels such as coal, oil, gas, and nuclear; also known as traditional power. cooling system program An energy efficiency program promotion aimed at improving the efficiency of the cooling delivery system, including equipment replacement, in the residential, commercial, and industrial sectors. cooperative electric utility An electric utility legally established to be owned by and operated for the benefit of those using its service, to generate, transmit, and/or distribute electric energy to a specified area not served by another utility. Most electric cooperatives were initially financed by the Rural Electrification Administration (REA) of the US Department of Agriculture. cost The amount paid to acquire resources, such as plant and equipment, fuel, and/or labor services. current (electric) The flow of electrons in an electrical conductor. The strength or rate of movement of the electricity is measured in amperes. default service Electricity service available to consumers who choose not to select an alternative electricity service provider. delivering party The organization supplying the capacity and/or energy to be transmitted at point(s) of receipt. demand (electric) The rate at which electric energy is delivered to or by a system, part of a system, or piece of equipment, at a given instant or averaged over any designated time period. demand-side management (DSM) The planning, implementation, and monitoring of utility activities designed to encourage customers to modify patterns of electricity usage, including the timing and level of demand. DSM activities cover the complete range of load-shape objectives, including strategic conservation and load management, as well as strategic load growth. demand-side management costs The costs incurred by a utility to achieve the capacity and energy savings from the DSM program(s). Costs are reported in dollars in the year in which they are incurred, regardless of
Glossary and useful terms
297
when the savings occur. Costs include expensed items to implement the program, incentive payments to consumers to install DSM measures, and annual operation and maintenance expenses incurred during the year. DSM costs are included in the ‘other costs’ category on the balance sheet. deregulation The process of changing the laws and regulations that control the electric, gas, and water industries to allow competition of service and sales. This results in customer choice of a utility provider. designated agent Any organization that performs actions or function on behalf of the transmission provider and eligible customer, or the transmission customer as required under the tariff. direct load control Program activities that can interrupt consumer load at the time of annual peak load by direct control of the utility system operator or by interrupting power supply to individual appliances or equipment on consumer premises. It excludes interruptible load and other load management effects. direct utility cost A utility cost identified with one of the DSM programs such as energy efficiency, direct load control, interruptible load, other load management, other DSM programs, and load building. distillate fuel oil A general classification for one of the petroleum fractions produced in conventional distillation operations. It is used primarily for space heating, diesel engine fuel, and for electric power generation. It includes fuel oil numbers 1, 2, and 4, and diesel fuel, numbers 1, 2 and 4. distribution The low voltage system of power lines, poles, substations and transformers, underground pipes and local storage, directly connected to homes and businesses. Distribution companies are the utilities that deliver product to homes and businesses over these wires and pipelines. distribution system The portion of an electric system that is dedicated to delivering electric energy to an end user. diversity exchange An exchange of capacity or energy, or both, between systems whose peak loads occur at different times. electric plant (physical) A facility containing electric generators and auxiliary equipment for converting mechanical, chemical, and/or fission energy into electric energy. electric rate schedule A statement of the electric rate and terms and conditions governing its application, including attendant contract terms and conditions that have been accepted by a regulatory agency or other body with appropriate oversight authority.
298
Glossary and useful terms
electric utility A corporation, person, agency, authority, or other legal entity or instrumentality that owns and/or operates facilities for the generation, transmission, distribution, or sale of electric energy primarily for use by the public. Facilities that qualify as cogenerators or small power producers under the Public Utility Regulatory Policies Act (PURPA) are not considered utilities. energy Energy is defined as the capacity doing work. It is measured in two different ways (1) as the inherent capability within a fuel of carrying out work, or (2) by the actual conversion of this capability to motion (kinetic energy). Energy has several forms, some of which are easily convertible and can be changed to another form useful for work. Most of the world’s convertible energy at this time comes from fossil fuels that are burned to produce heat that is then used as a transfer medium to mechanical work or other processes in order to accomplish tasks. energy charge That portion of the charge for electric service based upon the electric energy (kWh) consumed or billed. energy deliveries Energy generated by one electric utility system and delivered to another system through one or more transmission lines. energy effects The changes in aggregate electricity uses (measured in megawatt hours) for customers that participate in a utility DSM program. Energy effects should represent changes at the consumer meter and reflect only activities that are undertaken specifically in response to utilityadministered DSM programs, including those activities implemented by third parties under contract to the utility. energy efficiency programs Programs that are aimed at reducing the energy used by specific end-use devices and systems, typically without affecting the services provided. These programs reduce overall electricity consumptions (reported in megawatt hours). Savings are generally achieved by substituting technically more advanced equipment to produce the same level of end-use services with less electricity. Examples include high-efficiency appliances, efficient lighting, and efficient heating and/or air conditioning. energy receipts Energy generated by one electric utility system and received by another system through one or more transmission lines. energy source The primary source that provides the power that is converted to electricity through chemical, mechanical, or other means. Energy sources here include coal, petroleum and petroleum products, natural gas, water, uranium, wind, sunlight, geothermal, biomass, and other sources.
Glossary and useful terms
equity capital of stocks.
299
The sum of capital from retained earnings and the issuance
expenditure The incurrence of a liability to obtain an asset or service. facility An existing or planned location or site at which electric generators, and/or equipment for converting mechanical, chemical, and/or nuclear energy into electric energy are situated, or will be situated. For a cogenerator, the facility includes the industrial or commercial process. Federal Energy Regulatory Commission (FERC) A quasi-independent regulatory agency within the US Department of Energy having jurisdiction over interstate electricity sales, wholesale electric rates, hydroelectric licensing, natural gas pricing, oil and gas pipeline rates, and gas pipeline certification. Federal Power Act First enacted in 1920 and amended in 1935, the Act consists of three parts: Eventually incorporated into the Federal Water Power Act, the first part dealt almost exclusively with licensing non-Federal hydroelectric projects. Parts II and III were added with passage of the Public Utility Act and extended the Act to include regulating the interstate transmission of electrical energy and rates for its sale as wholesale in interstate commerce. The FERC administers this law. Additional major revisions were enacted in 1992. Federal Power Commission The predecessor agency of the FERC, this agency was formed with passage of the Federal Water Power Act of 1920 and charged with regulating the electric power and natural gas industries. The FPC was abolished in 1977 when the Department of Energy was created. Its functions were divided between the Department of Energy and the FERC. federal reserved rights (water) Water rights that attach to federal land set aside by Congress or the president for a particular purpose. FERC
The Federal Energy Regulatory Commission.
firm gas Gas sold on a continuous and generally long-term contract. firm power Power or power producing capacity intended to be available at all times during the period covered by a guaranteed commitment to deliver, even under adverse conditions. firm transmission service Point-to-point transmission service that is reserved and/or scheduled for a term of one year or more and that is of the same priority as that of the transmission provider’s firm use of the transmission system. Firm transmission service that is reserved and/or scheduled
300
Glossary and useful terms
for a term of less than one year is considered to be ‘Short-Term Firm Transmission’ for purposes of service liability. flue gas desulphurization unit (scrubber) Equipment used to remove sulfur oxides from the combustion gases of a boiler plant before discharge to the atmosphere. Chemicals, such as lime, are used as the scrubbing medium. flue gas particulate collectors Equipment used to remove fly ash from the combustion gases of a boiler plant before discharge to the atmosphere. Particulate collectors include electrostatic precipitators, mechanical collectors (cyclones), fabric filters (baghouses), and wet scrubbers. fly ash Particle matter from coal ash. Fly ash is removed from flue gas using flue gas particulate collectors such as fabric filters and electrostatic precipitators. fossil fuel Any naturally occurring organic fuel, such as petroleum, coal, and natural gas which was formed from the remains of prehistoric life. fossil-fuel plant A electricity generating plant using coal, petroleum or gas as its source of energy. fuel Any substance that can be burned to produce heat, including coal, petroleum, gas, biomass, etc. Also, materials that can be fissioned in a chain reaction to produce heat. fuel expenses Utility costs that include the fuel used in the production of steam or driving another prime mover for the generation of electricity. Other associated expenses include unloading the shipped fuel and all the handling of the fuel up to the point where it enters the first bunker, hopper, bucket, tank, or holder in the boiler house structure. full-forced outage The net capability of main generating units which are unavailable for load for emergency purposes. gas A fuel burned under boilers and by internal combustion engines for electric generation. These include natural, manufactured, waste gas, and methane collected from solid waste disposal facilities. gas turbine A gas turbine typically consists of an axial-flow air compressor, one or more combustion chambers, where liquid or gaseous fuel is burned and the hot gases are passed to the turbine and where the hot gases expand to drive the generator and to run the air compressor. gas turbine plant A plant in which the prime mover is a gas turbine.
Glossary and useful terms
301
gasification The process of producing power from biomass gas containing hydrogen, methane, carbon monoxide, nitrogen, water, and carbon dioxide. The term also refers to the production of synthetic gas from coal. generating unit Any combination of physically connected generators, reactors, boilers, combustion turbines, or other prime movers operated together to produce electric power. generation (electricity) The process of producing electric energy by transforming other forms of energy; also, the amount of electric energy produced, expressed in watt-hours (Wh). generator energy.
A machine that converts mechanical energy into electrical
generator nameplate capacity The full-load continuous rating of a generator, prime mover, or other electric power production equipment under specific conditions as designated by the manufacturer. Installed generator nameplate rating is usually indicated on a nameplate physically attached to the generator. geothermal plant A plant in which the prime mover is a steam turbine. The turbine is driven either by steam produced from hot water or by natural steam that derives its energy from heat found in rocks or fluids at various depths beneath the surface of the earth. gigawatt (GW) One billion watts. gigawatt hour One billion watt-hours. global climate change Gradual changing of global climates due to buildup of carbon dioxide and the greenhouse gases in the earth’s atmosphere. good utility practice (GUP) Any of the management practices, methods, and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period. Or, it can be any of the practices, methods, and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at the lowest reasonable cost consistent with good business practices, reliability, safety, and expedition. Good utility practice is not intended to be limited to the optimum practice, method, or act to the exclusion of all others, but rather to be acceptable practices, methods, or acts generally accepted in the region and consistently adhered to by the transmission provider. grandfathered rights When a state restricts water use but exempts existing users from the new limit, those existing users have grandfathered rights.
302
Glossary and useful terms
greenhouse effect The increasing mean global surface temperature of the earth caused by gases in the atmosphere. The greenhouse effect allows solar radiation to penetrate but absorbs the infrared radiation returning to space. greenhouse gases Gases resulting from the burning of fossil fuels and other sources; they include carbon dioxide, methane, nitrous oxides, ozone, and chloroflurocarbons. For many years, chloroflurocarbons were the preferred propellant manufacturers used in nearly all aerosol products; until recently these same elements were included in refrigerator and air conditioning coolants. grid
The layout of an electrical transmission or distribution system.
gross generation The total amount of electric energy produced by the generating units at a generating station or stations, measured at the generator terminals. ground water Water located beneath the surface of the earth. A groundwater system is a geologic grouping of adjacent aquifers. heating system Energy efficiency program promotion aimed at improving the efficiency of the heating delivery system, including replacement, in the residential, commercial, or industrial sectors. heavy oil The fuels remaining after the lighter oils have been distilled off during the refining process. Except for start-up and flame stabilization, virtually all petroleum use in steam generating plants is heavy oil. hourly non-firm transmission service Point-to-point transmission that is scheduled and paid for on an as-available basis and is subject to interruption. hydroelectric plant A plant in which the turbine generators are driven by falling water. incremental effects The annual effects in energy use (measured in megawatt hours) and peak load (measured in kilowatts) caused by new participants in existing DSM programs and all participants in new DSM programs during a given year. indirect utility cost A utility cost that may not be meaningfully identified with any particular DSM program category. They may be attributable to one of several accounting cost categories, such as administrative, marketing, monitoring and evaluation, utility-earned incentives, and other, but not including DSM program costs. industrial sector The industrial sector is defined as manufacturing, construction, mining, agriculture, fishing, and forestry establishments.
Glossary and useful terms
303
interdepartmental service (electric) This includes amounts charged by the electric department at tariff or other specified rates for electricity supplied by it to other utility departments. intermediate load (electric system) The range from base load to a point between base load and peakload. This point may be the midpoint, a percent of the peakload, or the load over a specified time period. internal combustion plant A plant in which the prime mover is an internal combustion engine. Diesel or gas-fired engines are the principal types used in electric plants. The plant is usually operated during periods of high demand for electricity. interruptible gas Gas sold to customers with a provision that permits curtailment or cessation of service at the discretion of the distributing company under certain circumstances, as specified in the service contract. interruptible load Program activities that, in accordance with contractual arrangements, can interrupt consumer load at times of seasonal peak load by direct control of the utility system operator, or by action of the consumer at the request of the system operator. It usually involves commercial and industrial consumers. kilowatt (kW)
One thousand watts.
kilowatt hour (kWh)
One thousand watt-hours.
leverage ratio A measure that indicates the financial ability to meet debt service requirements and increase the value of the investment to the stockholders. It is the ratio of total debt to total assets. liability An amount payable in dollars or by future services to be rendered. A utility’s contract to provide power or some other product to a customer is referred to as a liability; it is a legally binding requirement to provide some amount or level of service in return for the customer’s legal requirement to pay for that service. light oil Lighter fuel oils distilled off during the refining process. Virtually all petroleum used in internal combustion and gas turbine engines is light oil. lignite A brownish-black coal (also called ‘brown coal’) of low rank with high inherent moisture and volatile matter. Lignite is used almost exclusively for electric power generation. load (electric) The amount of electric power delivered or required at any specific point or points on a system. The requirement originates at the energy consuming equipment of the consumers.
304
Glossary and useful terms
load building Programs that are aimed at increasing the usage of existing electric equipment or the addition of electric equipment. Load building is reported as a negative number. load management Activities taken to reduce power demand at peak load times or to shift some of the load to off-peak times. The main appliance affecting electricity peaks is air conditioning, which is often a target for load management. load ratio share Ratio of a transmission customer’s network load to the transmission provider’s total load, calculated on a rolling twelve-month basis. marketing cost Expenses directly associated with the preparation and implementation of the strategies designed to encourage participation in a DSM program. The category does not include general market and load research costs. maximum demand The greatest of all demands of the load that has occurred within a specified period of time. Mcf
One thousand cubic feet (a measurement used for gas).
megawatt One million watts. megawatt hour One million watt-hours. MMcf
One million cubic feet.
monitoring and evaluation cost Expenditures associated with the planning, collection, and analysis of data used to assess program operation and effects. It includes such activities as load metering. Customer surveys, new technology testing, and program evaluations that are intended to establish or improve the ability to monitor and evaluate the impacts of DSM programs, collectively or individually. municipal utility Typically, a non-profit utility that is owned and operated by the community it serves. native load customers The wholesale and retail customers on whose behalf the transmission provider, by statute, franchise, regulatory requirements, or contract, has undertaken an obligation to construct and operate the transmission provider’s system to meet the reliable electric needs of such customers. natural gas A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in porous geological formations beneath the
Glossary and useful terms
305
earth’s surface, often in association with petroleum. The principal constituent is methane. net capability The maximum load carrying ability of equipment, exclusive of station use, under specified conditions for a given time interval, independent of the characteristics of the load. net generation Gross generation minus plant use from all electric utility owned plants. The energy required for pumping at a pumped storage plant is regarded as plant use and must be deducted from the gross generation. net summer capability The steady hourly output which generating equipment is expected to supply to system load exclusive of auxiliary power, as demonstrated by tests at the time of summer peak load. network customers Entities receiving transmission service pursuant to the terms of the transmission provider’s network integration tariff. network integration transmission service Service that allows a transmission customer to integrate, plan, economically dispatch, and regulate its network resources to service its network load in a manner comparable to that in which the transmission provider uses its system to serve its native load customers. network load The total load requirement of a transmission system operator; it is the sum of the loads of all member distribution systems in the system operator’s total network including the entire load of all member systems. A transmission customer’s network load is a fixed amount; it may not be reduced by the transmission customer or its member systems to reflect any portion of the load that is supplied by any generating facilities owned, or generation purchased, from these or other suppliers. new construction An energy efficiency program promotion designed to encourage the building of new homes, buildings, and plants to exceed standard government-mandated efficiency codes; it may include major renovations of existing facilities. non-firm power Power or power producing capacity supplied or available under a commitment having limited or no assured availability. non-firm transmission service Point-to-point transmission service that is reserved and/or scheduled on an as-available basis and is subject to interruption. Non-firm transmission service is available on a stand-alone basis as either hourly or short-term non-firm transmission service. nonutility power producer A corporation, person, agency authority, or other legal entity or instrumentality that owns electric generating capacity
306
Glossary and useful terms
and is not an electric utility. Nonutility power producers include qualifying cogenerators and small power producers, and other nonutility generators without a designated franchised service area. North American Electric Reliability Council (NERC) A council formed in 1968 by the electric utility industry to promote the reliability and adequacy of bulk power supply in the electric utility systems of North America. NERC consists of ten regional reliability councils that cover essentially all the power regions of the contiguous United States, Canada, and Mexico. nuclear energy Nuclear energy is derived from the splitting or ‘fissioning’ of uranium atoms. nuclear fuel Uranium is mined, processed to increase the amount of fissionable material, and formed into fuel rods which are then placed in nuclear reactors. As the uranium atoms split, they generate heat which is converted to steam. nuclear power plant A facility in which heat produced in a reactor by the fissioning of nuclear fuel is used to drive a steam turbine. off-peak gas Gas that is to be delivered and taken on demand when demand is not at its peak. It is often priced below peak gas. ohm The unit of measurement or electrical resistance – the resistance of a circuit in which a potential difference of one volt produces a current of one ampere. operable nuclear unit A nuclear unit is ‘operable’ after it completes low power testing and is granted authorization to operate at full power. This occurs when it receives its full power amendment to its operating license from the Nuclear Regulatory Commission. other DSM programs A residual category to capture the effects of DSM programs that cannot be meaningfully included in any of the main program categories. The energy effects attributable to this category should be the net effects of all the residual programs. other incentives Energy efficiency programs that offer cash or noncash awards to electric energy efficiency deliverers, such as appliance and equipment dealers, building contractors, and architectural and engineering firms, that encourage consumer participation in a DSM program and adoption of recommended measures. other load management Refers to programs other than direct load control and interruptible load that limit or shift peak load from on-peak to offpeak time periods. Examples include space heating and water heating
Glossary and useful terms
307
storage systems, cool storage systems, and load limiting devices in energy management systems. outage The period in which a generating unit, transmission line, or other facility is out of service. overdraft Water withdrawn from an aquifer in an amount greater than recharge. parties The transmission provider and the transmission customer receiving service. passive solar energy Use of the sun to help meet the energy needs of a building through architectural design and/or materials. peak demand
The maximum load during a specified period of time.
peak load plant A plant usually housing old, low-efficiency steam units, gas turbines, diesels, or pumped storage hydroelectric equipment normally used only during the peak-load periods. peaking capacity Capacity of generating equipment normally reserved for operation during the hours of highest daily, weekly, or seasonal loads. plant A facility at which are located prime movers, electric generators, and auxiliary equipment for converting mechanical, chemical, and/or nuclear energy into electric energy. point(s) of delivery Point(s) of interconnection on the transmission provider’s transmission system where capacity and/or energy transmitted by the provider will be made available to the receiving party, as specified in the service agreement. point(s) of receipt Point(s) of interconnection on the transmission provider’s system where capacity and/or energy will be made available to the provider by the delivering party. point-to-point transmission service The reservation and/or transmission of energy on either a firm and/or non-firm basis from point(s) of receipt to point(s) of delivery, including any ancillary services that are provided by the transmission provider. potable water Water that is suitable for drinking. potential peak load reduction The amount of annual peak load reduction capability (measured in kilowatts) that can be deployed from direct load control, interruptible load, other load management, and other DSM program activities. It represents the load that can be reduced either by the
308
Glossary and useful terms
direct control of the utility system operator or by the consumer in response to a utility request to curtail load. power The rate at which energy is transferred. Electrical energy is usually measured in watts. Also used for a measurement of capacity. power marketers Businesses engaged in buying and selling electricity, but do not own generating or transmission facilities. Power marketers, as opposed to brokers, take ownership of the electricity and are involved in interstate trade. They must file with FERC for status as a power marketer. power pool An association of two or more interconnected electric systems having an agreement to coordinate operations and planning for improved reliability and efficiencies. prime mover The engine, turbine, water wheel, or similar machine that drives an electric generator; or, for reporting purposes, a device that converts energy to electricity directly (such as photovoltaic and fuel cells). prior appropriation The system of rights to surface water that rewards the earliest users with the greatest security (‘first-in-time is first-in-right’). public authority service Includes electricity supplied and services rendered to municipalities or divisions or agencies of state or federal government, under special contracts or agreements or service classifications applicable only to public authorities. Public Utilities Regulatory Policies Act of 1978 (PURPA) The legislation that requires electric utilities to purchase available electricity from cogeneration plants and small power producers. pumped storage hydroelectric plant A plant that usually generates electric energy during peak-load periods by using water previously pumped into an elevated storage reservoir during off-peak periods when excess generating capacity is available to do so. purchased power adjustment A clause in a rate schedule that provides for adjustments to the bill when energy from other electric systems is acquired and it varies from a specified unit base amount. qualifying facility (QF) A cogeneration or small power production facility that meets certain ownership, operating, and efficiency criteria established by the DERC. rate base The value of property upon which a utility is permitted to earn a specified rate of return as established by a regulatory authority. It generally represents the value of property used by the utility in providing service
Glossary and useful terms
309
and may be calculated by any one or a combination of these accounting methods: fair value, prudent investment, reproduction cost, or original cost. Depending on which method is used, the rate base includes cash, working capital, materials and supplies, and deductions for accumulated provisions for depreciation, contributions in aid of construction, customer advances for construction, accumulated deferred income taxes, and accumulated deferred investment tax credits. ratemaking authority A utility commission’s legal authority to fix, modify, approve, or disapprove rates, as determined by the powers given the commission by a state or federal legislature. reasonable use doctrine The system of groundwater rights which allows a property owner to pump a limitless amount of water as long as it is used on the owner’s land and for a beneficial purpose. receiving party The entity receiving the capacity and/or energy transmitted by the transmission provider to the point(s) of delivery. regional transmission group A voluntary organization of transmission owners, users, and other entities approved by the FERC to efficiently coordinate transmission planning, expansion, operation, and use on a regional and interregional basis. regulation The government functions of controlling or directing economic entities through the process of rulemaking and adjudication. renewable resources A resource is renewable if it can be naturally replenished. Examples include solar, wind, geothermal, biomass, and hydroelectric. reserve margin (operating) The amount of unused available capacity of an electric power system at peak load for a utility system as a percentage of total capacity. residential sector This sector includes the private household establishments which consume utility products for such purposes as space heating, water and water heating, air conditioning, lighting, refrigeration, cooking, bathing, clothes washing and drying, and related uses. restructuring The term used to describe a series of events whereby a vertically integrated utility functioning as a natural monopoly is required to divest certain segments and open others to competition. Usually this occurs in the retail electricity sales and electricity generation segments. It is sometimes erroneously used as a synonym for deregulation.
310
Glossary and useful terms
retail sector Sales covering electrical energy supplied for residential, commercial, and industrial end-use purposes. Other small classes, such as agriculture and street lighting, are also included in this category. riparian
Refers to a river or river system.
riparianism The system of water rights in the eastern U.S. that allows owners of property on a river or lake to use that water. rule of capture The system of groundwater rights with no restriction on the quantity of water that may be pumped or the location of its use. running and quick-start capability The net capability of generating units that carry load or have quick-start capability. In general, quick-start capability refers to generating units that can be available for load within a 30-minute period. scheduled outage The shutdown of a generating unit, transmission line, pipeline, or other facility for inspection or maintenance, in accordance with an advance schedule. service agreement The initial agreement and any supplements thereto entered into by the transmission customer and transmission provider for service. small power producer (SPP) A small power production facility or small power producer that generates electricity using waste, renewable, or geothermal energy as a primary energy source. Fossil fuels may be used, but the renewable component must provide at least 75 percent of the total energy produced. spinning reserve The reserve generating capacity running at a zero load and synchronized to the electric system. spot purchases A single shipment of fuel or volumes of fuel purchased for delivery within one year. Spot purchases are often made by a user to fulfill a certain portion of energy requirements, to meet unanticipated energy needs, or to take advantage of low fuel prices. stability The property of a system or element by virtue of which its output will ultimately attain a steady state. The amount of power that can be transferred from one machine to another following a disturbance. The stability of a system is its ability to develop restoring forces equal to or greater than the disturbing forces so as to maintain a state of equilibrium. standby facility A facility that supports a utility system and is generally running under no load. It is available to replace or supplement a facility normally in service.
Glossary and useful terms
311
standby service Support service that is available, as needed, to supplement a consumer, a utility system, or to another utility if a schedule or an agreement authorizes the transaction. The service is not regularly used. steam electric plant (conventional) A plant in which the prime mover is a steam turbine. The steam used to drive the turbine is produced in a boiler where fossil fuels are burned. substation A facility with equipment that switches, changes, or regulates electric voltage. sulfur One of the elements present in varying quantities in coal which contributes to environmental degradation when coal is burned. switching station A facility with equipment used to tie together two or more electric circuits through switches. The switches are selectively arranged to permit a circuit to be disconnected, or to change the electric connection between the circuits. system (electric) Physically connected generation, transmission, and distribution facilities operated as an integrated unit under one central management, or operating supervision. total dissolved solids (TDS) A measure of the minerals dissolved in water. total utility costs This refers to the sum of the total direct and indirect utility cost for the year. transformer An electrical device for changing the voltage of alternating current. transmission The movement or transfer of electric energy over an interconnected group of lines and associated equipment between points of supply and points at which it is transformed for deliver to consumers, or is delivered to other electric systems. transmission provider A for-profit or nonprofit organization established to manage a transmission system. The provider may or may not own the transmission lines. transmission system An interconnected group of electric transmission lines and associated equipment for moving or transferring electric energy in bulk between points of supply and points at which it is transformed for delivery over the distribution system lines, or is delivered to other electric systems. treatment plant A facility where water or wastewater is treated using various physical or chemical processes.
312
Glossary and useful terms
turbidity The term that refers to the lack of transparency of water due to suspended particles, resulting in a cloudy or muddy appearance in the water. turbine A machine for generating rotary mechanical power from the energy of a stream of fluid (such as water, steam, or hot gas). uniform system of accounts Prescribed financial rules and regulations established by the FERC for utilities subject to its jurisdiction under authority granted by the Federal Power Act. voltage reduction Any intentional reduction of system voltage by 3 percent or greater for reasons of maintaining the continuity of service of the bulk electric power supply system. watt The electrical unit of power. The rate of energy transfer equivalent to one ampere flowing under a pressure of one volt. watt-hour A unit of energy equal to a power of one watt operating for one hour, 1000 watt-hours is equal to a kilowatt-hour. wheeling service The movement of electricity from one system to another over transmission facilities of intervening systems. Wheeling service contracts can be established between two or more systems. wholesale sales Energy supplied to other electric utilities including cooperatives, municipally owned utilities, and federal and state electric agencies for resale to ultimate consumers.
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Name Index Abbot, Arlene M. 185 Abrams, Robert H. 254, 256 Agranoff, Robert 211, 212, 214 Alvey, Jennifer 155 Anderson, David L. 146 Aristotle 49 Asmus, Peter 30 Balkin, David B. 195 Barnes, Irston R. 1, 8, 12 Barzelay, Michael 107 Beecher, Janice A. 29 Beder, Sharon 2, 57, 232 Bellenger, Gail 65 Berinato, Scott 267 Berrie, Tom W. 90, 126, 270, 288 Bezdek, Roger H. 164 Birchall, Johnston 205 Bolet, Adela Maria 90 Boone, Louis E. 76, 77, 99 Bovée, Courtland L. 167, 189 Bozeman, Barry 168, 192, 211 Braxton, John M. 43 Bremman, Timothy J. 54, 82, 109, 122, 131, 133, 144 224, 228, 236 Bridger, Jeffrey Hyman, Drew 20–21 Brown, Matthew H. 38, 236 Brush, Charles F. 23 Bryant, Kieth L. 11, 24 Bryson, John M. 74 Bruchley, Stuart 196, 201, 209, 216 Burkhart, Lori A. 157 Burgelman, Robert A. 108, 146 Burns, Robert 65 Burr, Michael T. 41, 176, 184, 207 Bush, George W. 266 Cardy, Robert L. 195 Carr, T.R. 17, 38 Carter, Jimmy 30, 37, 63 Caston, Melissa 47, 53
Cayer, N. Joseph 38 Chandler Alfred D. Jr. 9, 17, 22, 55 Chase, David A. 139, 140 Chertow, Marian R. 283, 289 Christensen, Clayton M. 108, 146 Christensen, Tom 9 Ciolek, Mark 110 Clair, Judith A 105–106 Clough, Shepard B. 102 Cochran, Clark E. 17, 38 Colburn, David R. 18 Connor, Ian 271 Cooper, Terry L. 53 Costello, Kenneth W. 65 Craddock, Jamie 60, 64, 247, 249 Crew, Michael A. 70, 253, 267 Cross, Phillip S. 116 Cumming, Charles M. 139, 140 Danielsen, Albert L. 126 Davis, Esterine 138 Denhardt, Katherine G. 51 Dethloff, Henry C. 11, 24 Dimock, Marshall E. 203 Donaldson, Thomas 12, 46, 52, 53 Douglass, Elizabeth 42 Dunfee, Thomas W. 12, 46, 52, 53 Eadie, Douglas C. 77 Edison, Thomas 23 Ely, Richard T. 14, 18 Esty, Daniel C. 283, 289 Evans, Willard 154–5 Fandt, Patricia M. 73 Farris, Martin T. 10, 12, 23, 26, 91, 95, 96. 109, 145, 188, 202 Felak, Richard P. 272 Finon, Dominique 272 Fox, Mary F. 43 Frenzel, Carroll W. 152, 162
327
328
Name Index
Garofalo, Charles 45–6, 51–53 Genieser, Kevin 204 Gent, Chris 184 Gerstberger, Richard L. 147 Geuras, Dean 51, 53 Ghahramani, Bahador 159 Glaeser, Martin G. 12, 57, 118, 145, 153–6, 199, 204, 252, 254 Glennon, Robert 260, 287 Gomez-Mejia, Louis R. 195 Goodman, Stephen H. 73 Gordon, Richard L. 56 Goss, Robert P. 50, 51, 53 Hakim, Simon 17, 126, 256, 261–2, 268 Hampton, Howard 216 Hays, Steven W. 191, 193 Helgesson, Claes-Fredrik 14, 121 Heller, Mariam 147 Helman, Christopher 273 Hendrick, Gary R. 227 Hodgkinson, Christopher 99 Hogue, Bill 60, 64, 247, 249 Houston, E. H. 23 Hughes, Owen E. 15, 149 Hull, Robert W. 7, 10 Hull, William J. 7, 10 Hyman, Drew 20–21 Ilic, Marija 130 Ingraham, Patricia W. 187–8 Insull, Samuel 26, 57 Jackson, Andrew 9 Jacobson, Charles David 38 Jacobson, Willow 187–8 Johnson, Michael D. 130, 137 Johnson, Tor Arnt 272 Jones, Wallace 110 Joseph, Sarah 47, 53 Joskow, Paul L. 90, 120, 221, 236 Kamarck, Elaine 149 Kamerswchen, David R. 126 Kant, Emmanuel 46 Kaschub, William 191, 192 Katz, Sara M. 137 Kearney, Richard C. 191, 193 Kearns, Grover S. 145, 147 Keating, John D. 78
Keating, Ross 78 Kenesok, Jim 154 Kennedy, Jon 75 Kennedy, Michael A. 137, 157 Kent, Calvin A. 57, 59 Keohane, Robert O. 196 Kettl, Donald F. 108, 216 Kliendorfer, Paul R. 70, 253, 267 Koontz, Harold D. 205 Kurtz, David L. 76–7, 99 Læ´greid, Per 9 LaFollette, Marcel C. 41 Lashgari, Malek 199 Lassiter, Ralph 75 Laudon, Jane P. 146, 162 Laudon, Kenneth C. 146, 162 Lauer, William C. 195, 268 Lederer, Albert L. 145, 147 Leshy, John D. 254, 256 Lester, Lisa Y. 137, 157 Lewis, Pamela S. 73 Lewis, Peter 41 MacAvoy, Paul W. 62, 237, 243, 244, 245 Maidique, A.M. 108 Malhotra, Naresh K. 46 Marburg, Theodore F. 102 Mariner-Volpe, Barbara 237, 245 Martinez, Salvador A. 54, 82, 109, 122, 131, 133, 144, 224, 228, 236 Mattoon, Richard 25–6, 33 Mayer, Lawrence C. Mayer 38 McCann, Justin 219–221, 230 McCarthy, Jerome 131, 144 McGuire, Michael 211, 212, 214 McLean, E.R. 146 McLeod, Raymond Jr. 146, 151, 162 Mescon, Michael H. 167, 189 Midttun, Atle 272 Milward, H. Brinton 108 Morison, Samuel Eliot 5, 9, 18 Morrison, Matt 106 Nadol, Michael 17, 126, 256, 261–2, 268 Nanus, Burt 99 Napolitano, Frank 165 Nye, Joseph 196
Name Index Orlans, Harold 50 Osborne, David 93 Owens, Brandon 96 Palmer, Karen L. 54, 82, 109, 122, 131, 133, 144, 224, 228, 236 Parrington, Vernon L. 22 Patterson, K.D. 51 Pearce, John A. 74, 76, 100 Pearson, Christine M. 105–106 Perreault, William D. Jr. 131, 144 Peterson, Karen 40 Petrick, Joseph A. 52 Plastrik, Peter 93 Post, Gerald V. 146 Pozzetta, George E. 18
329
Seines, Fred 130, 137, 157 Seldon, Sally C. 187 –8 Senn, James A. 146 Shaw, John 84 Shere, Craig 237, 240, 243, 245, 248–9, 251, 284 Shinger, John Hyman 20–21 Showman, Jeffrey 27 Smeloff, Ed 30 Smith, Adam 9 Sparks, William O. 204 St. Thomas Aquinas 49 Starling, Gover 108, 147, 152, 195 Stavros, Richard 166 Stoft, Steven 126, 134 Straussman, Jeffrey D. 168, 192, 211 Strickland, A. J. III 96
Quinn, John F. 52 Rachman, David J. 167, 189 Reagan, Ronald 3 Redano, Richard P. 236 Reed, William L. 121 Rhee, Hyen-Suk (Sue) 148–50 Riggins, Frederick J. 148–50 Robinson, Colin 38 Robinson, Richard B. 74, 76, 100 Rodriguez, Augusto 75 Rogoff, Mark J. 75, 262 Rohr, John A. 41, 53 Roosevelt, Franklin D. 26, 37, 56, 69, 204 Roosevelt, Theodore 196 Rubin, Scott J. 29 Ruth, Joao-Pierre S. 191, 272 Said, Carolyn 39 Sampson, Roy J. 10, 12, 23, 26, 91, 95, 96, 109, 145, 188, 202 Sax, John L. 254, 256 Scalingi, Paul L. 106 Schell, George 146, 151, 162 Schoenberger, Chana 273 Schmalensee, Richard 90 Schneider, Gary P. 151, 157, 162 Schuler, Joseph F. 183 Schultz, Jenny 47, 53 Schwartz, David S. 63 Sedano, Richard P. 38 Seidenstat, Paul 17, 126, 256, 261–2, 268
Tedlow, Richard S. 22 Teske, Paul 67, 68 Thatcher, Margaret 15 Thill, John V. 167, 189 Thompson, Barton H. Jr. 254, 256 Thompson, Arthur A. Jr. 96 Thomson, Elihu 23 Trapmann, William 247, 251 Turban, Efrain 146 Van Loon, Mollie 20–21 Velasquez, Manuel 43, 45, 48 Vital, Tina 241, 248 Von Sacken, Eric W. 147 Waite, Chief Justice Morrison R. 10, 12 Warkentin, Denise 144, 243 Warren, Charles 204 Watkins, Sherron 40–41 Weatherbe, James 146 Weber, Max 3, 9, 92, 107 Weiss, Carol H. 87 Wending, Robert M. 164 Westinghouse, George 23 Wheelwright, Steven C. 108, 146 Wherry, Rob 273 Wickwar, W. Hardy 70 Wilson, James Q. 70 Wilson, William 110 Wilson, Woodrow 3, 107 Woller, G. M. 51
Subject Index ABS Energy Research 28 Academy of Management 40 Accelerated shift 7 Accenture Resources 137 Accountability 3 Accounting function 168 Accounting, four services in utilities 181 ACI Corp. (WGL Holdings) 141 Action plans 89 Adequate supplies 8 Adversarial contract negotiations 190 AES Corporation of Arlington, Virginia (AES) 78, 98 Affected with a public interest 10, 22 Agrarian character 8 American Institute of Certified Public Accountants (AICPA) 177, 181 Alabama 239 Alaska 248, 249, 282 Alaska Systems Coordinating Council 142 Alberta 78 Algeria 249 All Electric 10 All gas systems 120 America 6, 22, 196 America’s failed experience with Prohibition 44 American business 68, 201 American Electric Power Co. 41 American Gas Association (AGA) 248 American Middle West 198, 288 American Public Power Association (APPA) 174, 184, 194 American Water Works Association (AWWA) 137, 167, 169, 176, 181, 284–5, 287, 289 American West 256 Amortization model 20 Analysis 96, 101 Ancillary services 223, 268
Annual reports 177, 178 AquaStructure 81 Aqueducts 25 Aquifers 247 Arbitrators 190 Arc-light system 23 Arctic gas 248 Arizona 80, 84, 85, 288 Arizona Public Service 85 Arkansas 239 Arlington, Virginia 98 Artesian 186 Artesian Resources 80, 186 Artesian Resources Corporation 80, 185 Artesian Water 186, 187 Artesian Water Company 81 Arthur Anderson 40 Artificial intelligence (AI) 152 Artificial monopolies 14 Artificial shortages 42 Asia 35, 248, 275 Atlantic 282 Atlantic City casino industry 200 Atlantic City resort 200 Attracting, retaining and developing employees 193 August 2003 blackout 279 Australia xii, 16, 35 Australian utility privatization 232 Authoritative administrative regulatory system 3 Automated systems 265 Average load 112, 126 Aviation use 64 Avista Corp 154 Back loading 130 Bahamas 282 Balance sheet and income statements 178 Baltimore, Maryland 11 330
Subject Index Banishing Bureaucracy 93 Bankruptcy 182 Bargaining unit 185 Basic Cooperative Services 207 Basin Electric Power Cooperative (BEPC) 206, 207 Basin Telecommunications 207 Basis for determining the allowable rate of return 117 Basis for rule ethics 46 Bates Technical College xvi Business Ecology (BE) process 147 Behaviors and attitudes expressed by legislatures 21 Benchmarking 95 Benchmarking study 154 Bethlehem, Pennsylvania 11, 252 Biggest mega trend 182, 194 Bills of Rights 47 Bioterrorism preparedness 286, 289 Bismarck, North Dakota 207 Blackout 1, 219 Block rate 119 Board members 199, 215 Boeing Company 64, 106 Boise, Idaho 154 Bonneville Power Administration (BPA) 26, 33, 34, 37, 57, 61, 82, 94, 106, 136, 204, 222, 276 Bonus opportunities 190 Boston 11, 249, 252, 254 Boulder Canyon Project Act of 1928 209–10 BPA 82, 276 Brackish 260 Brain Drain 184 Brazil xii, 16 Britain 5, 6 British 6, 253 and Irish Catholics 5 BNFL Group 273 citizens 5 justice 203 rule 4 British Columbia 78 British Columbia Gas 106 British Columbia Hydro 106 British Columbia Provisional Emergency Program 106
331
British Thermal Unit (BTU) 241, 272 British utility management firm 191 Brownout and blackouts/electricity sector 3 Brush system 23 BTInet 207 Bureau of Reclamation (BOR) 258 Bureau’s water projects 258 Burnertip prices 246 Bus transportation 11 Business lobbies 15 Buyers of power 222 Cable television system 14 Cable television xi California 33, 34, 40, 61, 80, 83. 197, 221, 222, 233, 244, 257, 258, 269, 271, 287, 288 and Enron 68 Central Valley 261 deregulation 68, 197 electric power industry 41 electricity crisis 21, 32, 41, 197 energy reorganization process 104 experience 75 generating plants 42 legislators 42 project 258 Public Utility Commission 42 regulators 41 reorganization process xv, 166 State water Project 258 Water Board 136 Calpine Corporation 185, 186, 282 Canada 35 Canada blackout 21 Canada xii, 16, 78, 197, 202, 219, 225, 227, 228, 271, 282, 287, 289 Canadian Hydro Developers, Inc (Canadian Hydro) 78–9 Canadian imports 282 gas fields 282, 289 natural gas 248 pipeline deliveries (Vital 2004) 248 Province of Ontario 219 task force 219 Canal construction 4 Capacity of all transmission lines 220 331
332
Subject Index
Capital acquisition 163 as a key resource 165 of a holding company 201 Capital-intensive industries 25, 199 Capital-recovery fee 170 Carbon dioxide 284 Caring Ethics 48 Cartels and trusts 58 Munn v. Illinois 10, 23 Cash awards 193 Casino industry 200 Catalyst of fundamental changes 146 Catalytica Energy Systems, Inc (CES) 80 CenterPoint Energy Arkla 221, 238, 239 CenterPoint Energy Entex 239 CenterPoint Energy Minnegasco 239, 245 Central and Eastern U.S. 227 Central Hudson Gas & Electric Corporation 98 Central marketing issue 130 Centralized services 176 CES Company Profile 80 CH Energy Group 98 Charges for interstate transportation 244 Chelan County Public Utility District 158 Chelan County PUD in Wenatchee, Washington 185 Chelan County, Washington 77 Chester County 81 Chicago, Illinois 10, 26, 57, 154 Chief challenges 71 Chief Information Officer (CIO) 154 Chile xii Christian virtues 49 Church-dominated Utah legislature 257 Cinergy 156 Citizens’ committees xi City of New York 252 City of Perth Amboy 191 City of Shelton, Washington xvii, 213 City gate prices 246 City-owned utility 176 Civic Center Building 214
Civic water systems 8 Civil and political rights 47 Civil War (US) 8, 9, 22, 55, 203, 268 Civil War in Great Britain 5 Classic multi-organizational agreement 214 Classify rights 47 Clean Air Act Amendments 284 Clean Water Act (CWA) 65, 70, 259, 283 Clean Water Act of 1972 268 Clean Water State Revolving Fund 66, 259 Click! 159 Click! Network 159 Coal 22, 223, 225, 274 bed methane 282 gas plants 11 natural gas and petroleum 235 fired electric power generating plants 224, 274 fired steam turbine 223–4, 235 Coastal areas of the Middle Atlantic seaboard states 248 Coastal vessels 4 Collections model 20 Collective bargaining 189, 195 Collector of customs 9 Colonial and revolutionary North America 209, 252 Colonial institutions 5 Colonial system 4 Colorado 83, 257 Colorado River 204, 210 Columbia River dams 276 Columbia River project 276 Combined transportation, storage, and other services 243 Combine-Cycle Gas Turbine (CCGT) generators 224, 241 Commercial 135 and industrial customers 131 and Industrial Gas Services 239 justice 4 market 242 Commission orders by the Federal Energy Regulatory Commission 243 Commission’s jurisdiction 57 Communications 11
Subject Index Communications revolution 7 Community responsiveness 185 Community utilities 212 Commonwealth Edison 192 Compagnie Générales des Eaux 263 Company policy 36 Comparison of actual costs and operating statistics 179 Compensation 283 Compensation program 185 Compensatory justice 48 Competition 234 Competition at all levels of the industry 130 Competitive analysis 139 Complex governance system 203 Compliance with the RTO 230 Components of information technology 161 Comprehensive Environmental Response 283 Computer climate model 277 Computer-based information systems 145, 146 Computers 146 and complex telecommunications systems 145 and telecommunications technologies 160 Concept of strategic management xiii Condemnation of riparian water rights 257 Conectiv Solutions 200 Congestion overloads 219 Congress of the United States 33, 41, 42, 55, 57, 64, 68, 69, 212, 233, 242, 243, 251, 259, 276, 279, 280 Connecticut 219, 284 Consistency in reporting 180 Consolidated Electric & Gas Company 153 Consolidation 207 Constantinople 263 Constitution of the United States 209 Construction costs 224 and the Hoover Dam 210 of reservoirs 25 Consumer Cooperatives (Co-ops) 197, 206
333
Consumer protection rules 123 Consumer-owned utilities (COUs) 123 Consumers Public Power District 202 Contingency factor 115 Contract negotiations 189 power projects 166 prices 133 provisions 189 Control air and water pollution 283 Control Area Operators (CAOs) 228 Control process 90 systems 148, 161 of utility holding company excesses 220 Controlling the management function 100 the implementation of plans 136 Convert raw data 148 Co-op customer density 198 Co-op Model 206 Cooperative water organizations 257 Cooperatives (Co-ops) 25, 197, 198, 222 Coordinating systems 151 Corporate governance 196 Corporate policy 36 Corporation Finance Division 56 Corporations 199 Cost data and related operating statistics 179 Cost of building nuclear generating facilities 275 Cost shifts 116 Cost-containment 184 Costs attributable to operations 111 Court decisions 209 Cove Point Terminal 249 Crisis management 105, 107 Crisis planning 107 Critical set of challenges 177 Critical skills 84 Croton River 254 Crown Colonies 5 appointed governors 6 Court, 209 decisions 21 and the rights of municipality 209
334
Subject Index
Customer Application Maintenance System (CAMS) 159–60 Customer Information Database (CID) 160 Customer Information System (CIS) system 156–7, 161 Customer Owned Utilities (COUs) 123 Customer Relationship Management (CRM) 137–8, 157, 161 Customer service 185 Clean Water Act (CWA) 65 established rules 268 regulatory focus 66 rules 25 9 Cyberterrorism 267 Dakota Coal Co. 207 Dakota Gasification Co. 207 Damage to the grid and related equipment 219 Data warehousing 155, 156 Debt 165 Decision Support Systems (DSS) 152 Declining water tables 261 Delaware 80, 81, 186 Demand costs 112 for energy 139 for natural gas 237, 250 rates 120 for better governance 196 Demand-side management (DSM) 136 Demarketing 127, 129, 142 Democratic Party platform, election of 1932 102 Denver, Colorado 254 Department of Energy (DOE) 33, 62, 232, 274, 277, 282 Department of Homeland Security (DHS) 286 Department of the Interior (DOI) 258 Depleted fields 247 Depletion 287 Depression, the Great 57 Derailed industry 277 Deregulation 39, 103, 123, 126, 129, 182, 197, 221, 232, 234, 236, 243, 251 and reorganization 143 and restructuring 163
movement 68 of the utility industry 70 or restructuring 75 Desirability of natural gas 240 Determining costs 110 Determining specific combination of prices 109 Developing a comprehensive customer database 157 an organization profile 77 strategies xiii the marketing plan 136 Development of transportation 4 of water systems 252 Diesel electric locomotive 225 Diesel fuel 225 Different types of organizations 268 Digital utility concept 155 Directing implementation of the plan 136 the operations of an organization 99 Directors 185 Disposal sites 14 Disruptions of critical public services 106 Distinguishing moral standards 44 Distribution 231 companies 238 or processing 13 systems 135 utilities 125, 134 Distributive justice 48 District of Columbia 66, 190, 222, 244, 245, 260, 284 Diversity 126 Dominion Resources, Inc. 134 Donor–recipient management model 212 Dover, England 11 Downstream activities 238, 250 Drilling 25 Duke Energy 106 Dynamic nature of the CIS 157 EAI Corp 282 Early Utilities First system in New York City 252
Subject Index carrier ditch companies 247 utility integration 199 water systems 252 Eastern U.S. 231 East Central Area Reliability Coordination Agreement 142 East Coast of the U.S. 6, 282 East Indian (the US Census Bureau population category) 124 East Indians 124 Eastern Daylight Time 219 Eastern Interconnected System 227, 235 Eastern Interconnections 228 Eastern United States 219 Eclectic mix of private and public utilities 182 E-commerce 150, 161 Economic conditions 75 organizations 12 reality 102 upheaval 204 and social, and cultural rights 47 Edison 192 Company 23 Electric Institute 232 Electric Light Company 23 General Electric 23 Lamp Company 23 Education policies 19 Effective cost control 179 E-government 148, 149, 161 Egypt 11, 209 El Paso Electric Co. (EPE) 142, 226, 227, 242 El Paso, Texas 241 Elasticity 131, 143 Elba Island Terminal 249 Elective bargaining process 189 Electric power 223 for lighting purposes 11 industry 222, 230, 234, 238 infrastructure 272 systems 235 Electric Reliability Council of Texas 142 Electrical energy 11 ElectriCities 138 Electricity 12, 23, 32
335
and natural gas energy sectors xi and natural gas industries 199 blackouts 219 generation segment 241 industry 29, 278 Electronic commerce 148 commerce or simple e-commerce 161 customer relationship management 157 Electronic Customer Relationship Management (e-CRM) 157 E-Mainstream 284 Emergency Preparedness 106 Emissions 83, 227 Encompasses acts of deception 43 Encyclopedic review of the industry 145 End-use prices 246 Energy Act 201 Energy Atlantic 138 and Maine & New Brunswick Electric Power Co 153 Energy shocks in 1972, 1974, 1978, and 1980 62 Energy Information Administration (EIA) 88, 137, 221, 226, 289, 229, 230, 233–4, 236, 239, 246–7, 275, 28–3, 289 Energy crisis 233 market 132 policies 19 problems 197 shortage 42 Energy Policy Act of 1992 (EPAct) 31, 33, 60, 69, 87, 90 Energy Policy Commission 278 England 35 Enron 39, 40, 47, 68, 104, 138, 233, 250 collapse 41 chief financial officer 40 stockholders 40 Enterprise application integration 151 Environmental analysis 139 concern 128 groups 274 policies 19
336
Subject Index
pressures 83 regulations 273 stewardship 185 Environmental Protection Administration (EPA) 65–7, 142, 143, 212–13, 259–60, 263, 266, 284, 286, 289 authority 142 classifies water systems 254, 268 electronic report 66 establishes standards 142 mandates environmental standards 263 and state partnerships 66, 259 Equity investor-owned utilities 165 Estimate construction costs of new technology 275 Ethical dilemmas 49 Ethical standards 39, 43 Ethics definition of 43 and good governance 41 and responsibility 1 a branch of philosophy 43 Ethos 51, 52, 53 European Union (EU) 16, 35 Europe xi, 4, 5, 6, 8, 9, 25, 35, 130, 143, 197, 206, 253, 272 Everett, Washington 249 Evergreen State College xi Evolution of government involvement 204 Exelon Corporation 192 Exempt Wholesale Generator (EWG) 60, 67 Expert Systems (ES)152 Extensive consolidation of business 9 External analysis 74, 97 and internal constraints 101 data 178 environment 82 factors 90, 139 forces 109, 194 policy 19 surveys 74 Extortion 105 Extranets 150, 151 Extraordinary events 139 Extraordinary items include any unexpected gains or losses 172
Fair rate of return 116, 142, 171, 220, 231, 234 Far West 63 Federal and local government power 15 Federal Clean Air Act of 1970 283 Federal control 205 Federal Courts 10 Federal Emergency Management Agency (FEMA) 106 Federal Energy Bill of 2003 203 Federal Energy Regulatory Agency (FERA) 233 Federal Energy Regulatory Commission (FERC) 27, 31, 33–4, 36, 60–62, 67, 69, 123–5 212, 220, 228–30, 234–6, 244, 246, 277, 280, 290 Federal Environmental Protection Administration 65 Federal government 14, 22, 26, 103, 209, 215, 259 and the water industry 258 regulations 69 set artificially low regulated prices 251 development of power projects 209 participation 204 preference clause system 205 Federal grants 129 irrigation involvement 258 laws 211 legislation 127, 143, 259 operators 276 ownership 209 policy toward utilities 22 Federal Power Act of 1935 57, 69, 243 Federal Power Act of 1992 (FPA) 60, 61, 64 Federal Power Commission (FPC) 26, 56, 57, 62, 69, 70, 102, 205, 243 Federal power supply systems 57 Federal regulation of the energy industry 243 of utilities 69 Federal regulatory system 56, 69 Federal Reserve Bank 25 Federal state and local governments 19 Federal Trade Commission 102
Subject Index Federal Water Pollution Control Act of 1972 65, 70, 259 Federal Water Power Act 57, 69 Federally imposed pollution controls 237 Federally mandated preference status 276 Federally owned utilities 222 Fees and commissions 59 FERC Order 436 27, 64, 243, 251 FERC Order 500 27 FERC Order 636 28, 64 Fiber-optic communication systems 121 Final load factor 126 Finance function 181 Financial and statistical data flow 168 Financial management 167, 181 First World War 9 Five chief components of all information systems 161 Five human resources vice-presidents 194 Five important external constraints 107 Fixture rates 119 Flat charge rates 118 Flat charges 119 Flat or average-rate pricing 129 Flat rate 119, 127 Florida 184, 282, 287, 288 Florida legislatures 262 FOA 243 Folsom, New Jersey 200 Forbes magazine 273 Forecasting demand 139 Form 10-K annual financial report 76, 89 Forward-looking statements 74 Fossil fuels 225 Fragmented structure 35 France 16, 253 Franchise to construct and operate 14, 24 Fresh water 260 Ft. Lewis, Washington 133 Fuel cells 226 Fuel price shocks and shortages 220, 234 Fuel used for generating electricity 111
337
Fundamental concepts xiv Fundamental economic principle 13, 17 Fundamental management paradigm shift xii Fundamental purpose of the MIS 152 Fundamentals of rate setting 109 Futures market 128 Gallup 41 Gallup Poll, USA Today 40 Gap analysis 84 Gas (natural) 289 and wind turbines 14 distributors 237 group units 239 lights and electric power 203 prices 250 producers 63 shortage during the winter of 2000–01 247 storage 247–8 supply 200 turbine 64, 224 Gas-turbine generators 273 General Electric 94, 273 General fund 13 General Motors 94 Generating plant operators 42 Generation III 275 Generation, transmission, and distribution 32 Geothermal 235 Germany 16, 92, 107, 153 Greenhouse Gas Intensity (GGI) 283 Global payroll 16 Global Power Group 165 Global water 262 Goal of the control process 87 Goal setting and reward systems 140 Goals for a public participation program 137 Goals of the Tacoma Utility Business Systems Improvement Project 153 Governance 196, 198 Governance challenges xv Governance models 212 Governance of public utilities 34, 197, 214
338
Subject Index
paradigm shift 211 policies and actions reform 197 Government accounting system 176 agencies 177 financial managers in the annual report 177 organizations 177 participation 209 Policy xiv, 25, 37 regulation 6, 29, 62 regulation of the natural gas industry 70 Government involvement 215 Governmental Accounting Standards Board (GASB) 168 GASB System 168, 176–7, 181 Government-owned organizations 176 Grain elevators 12 Grand Coulee Dam 276 Granger Laws 10, 24, 55, 69 Granite Peak Energy, Inc 207 Grays Harbor County 81 Great Britain 5, 15, 94, 208, Great Depression xii, 15, 21, 7, 59, 196, 201, 243, 269 Great Plains 261 Greece 209 Green power market 133 Greenhouse gas intensity 283 Grid 61, 226 Grid West 277 Groundwater 261, 287–8 Gulf Coast 237, 250, 282 Gulf of Mexico 237 Hawaii 282, 287 Health problems 129 Heating oil delivery xi Hidden extreme wholesale prices 121 High Plains of the U.S. 287 High prices 129 High-pressure 128 Hispanic ancestry 124 Historical information 139 Holding companies 59, 201 Home rule charters 203 Home Service Plus® 245 Hoover Dam 204
Households 135 Houston, Texas 221, 238 Hudson River 98 Hudson’s Bay Colony, Canada 5 Human Resources activities 187, 195 department 184–5, 192 function 191 managers 183, 184, 194 needs 192 operations 192 staff 192 management (HRM) 182–3, 191 role in public utilities 140 Heating, Ventilation, and Air Conditioning (HVAC) 141 Hydroelectric dams 14 Hydroelectric generation capacity 276 Hydroelectric generators 225 Hydropower plant locations 273 IBM mainframe-based system 159 Idaho 154, 155 Idaho Bureau of Disaster Services 106 Idaho Power Co. 153, 155 Illinois 7, 40 203, 239, 247, 274 Illinois State legislature 10 Imbalance 83 Immigrants 6 Impact fees 170 Implementing planned activities 86 Imports in 2002 249 Inadequate supply 8 Income and deductions 172 Independent Energy Producers 42 Independent power producers 226 Independent Regional Transmission Operator (IRTO) 230 Independent System Operator (ISO) 61 India 209, 252 Indian sub-continent 11, 124 Indiana 7, 247 Individual councils 228 Individual firms 201 Individual states 67 Industrial (or business) Ecology (IE) 147 Industrial customers 135, 240 Industrial park 213 Industrial policies 19
Subject Index Industry analysts 221 Industry and policymakers 289 Industry consolidation 199 Inexpensive gas turbine generator 273 Information Management (IM) 145–6, 160 Information System Master File 159 Information Systems Technology (IST) 147 Information technology (IT) xv, 145, 146, 149, 160 Information technology management (ITM) 145, 160 Infrastructure 4 Infrastructure Security (see PMPRIS) 106 Initial government policy 24 Institute for Energy, Law and Enterprise 289 Integrated energy companies 234 Integrated resource planning (IRP) xiv, 88–90 Integrated utility information management 149 Integrated utility providers 127 Intent of the bargaining process 189, 195 Interconnected network of transmission lines 226, 235 Interconnected utilities 227 Interest charges 172 Internal analysis 97 Internal combustion engine 225 Internal data 178 Internal environment 82 Internal IT issues 154 Internal policy 19 International Personnel and Labor Relations Association (IPLRA) 193 Internal Revenue Code 186 Internal Revenue Service 168 International water holding companies 263 Internet 150, 151, 157 Internet-based communications technology 270 Inter-organizational application 150 Interpreting theory and data 96
339
Interstate commerce 58 Interstate Commerce Act 24 Interstate Commerce Commission (ICC) 24, 196, 203 Interstate Commerce Commission Act 96 Interties 226, 235 Intranet technology 151 Investor-owned utilities (IOUs) 13, 35, 39, 123, 140, 166, 169, 185, 197–8, 210, 211, 215, 222, 231, 269, 276 and publicly owned utilities 191 gas utilities 245 operations 176 plants 185 public utility 227 ‘Invisible hand’ 9 Involvement of employees 193 Iowa 239 Iron 22 Irrigation canals 256 Irrigation districts 257 Irrigators organize 257 Issue franchises and permits 202 Information Technology (IT) 145, 146, 147 applications 152 consulting firms 157 experiences 155 in utilities 146 investment 153 program planning and design experiences 153 requirements 159 resources 160 spending plans 154 system in the utility 146, 160 systems 153 Information Technology Management (ITM) 145 Italy 16 Japan 95, 192, 282 Juarez, Mexico 227 Jurisdiction-based activity (JBA) 214 governance model 213 model 212, 215, 216 Just and reasonable test 26 Justice Ethics 48
340
Subject Index
Kansas 79, 239 Kansas City Gas and Electric 79 Kantian rule-based rights theories 47 KBC Advanced Technologies, Inc 192 Kentucky 239 Key finance challenges 181 Kissimmee Utility Authority (KUA) 184 Kissimmee, Florida 184 Kitsap County 81 Knavery 50 Knowledge manager xvi Labor relations 189 Labor Relations of the American Society for Public Administration 193 Labor relations process 195 Labour Party 15 Lacey, Washington 255 Laissez-faire economic approach 4 Lake Charles Terminal 249 Land development fees 170 Large investor-owned utilities 141 Large municipal operation 197 Large utilities and industrial customers 276 Latin America 35 Laws of particular concern 283 Local Distribution Company (LDC) 238, 243, 245, 250 Leadership from Within 185 Leadership skills 99 Lean Management Information System (LMIS) 159 Least understood concepts in utility management xiv Legacy systems 159 Legal actions and constraints 103 Legal and economic constraints of public utilities 96 Legal challenges to Order 451 244 Legal right of government to acquire 33 Legally sanctioned price discrimination 13 Lehman Brothers Investment Bank 165 Liability Act of 1980 283 Lighting systems 25
Limited Liability Corporation 81 Liquefied Natural Gas (LNG) 65, 248–9, 282, 289 port and storage facilities 248 regasification terminals 249 LJM Corp. (Enron) 40 Lean Management Information System (LMIS) 159 Load factor 115 Load-duration curve 139 Local distribution companies (LDCs) 238 Loop flow 219 Lord Baltimore’s Maryland Colony 5 Lord Chief Justice of England 203 Los Angeles, California 254 Loss of critical knowledge 184 Louisiana 239, 247, 249 Lower utility costs 131 Maine & Maritimes Corporation (MAM) 138, 153 Maine 103 Maine Public Service Company (MPSC) 41, 104, 153–4 Maine Public Utility Comission (MPUC) 103 Maintaining product quality and reliability 142, 143 Maintenance, operations, and record keeping 42 Management 71, 74, 91, 106, 107, 189 by objectives (MBO) 95 costs 111 discussion and analysis (MD&A) 177 in public utility organizations 92 information systems (MIS) 151 of public service 211 policy 20 problems 146 responses 140 Managers 109 moral behavior 52 in municipal water utilities 265 use of MIS-produced data 152 Managing for results 136 Managing implementation of the program 136 Managing utilities 93
Subject Index Management Discussion and Analysis (MD&A) in annual reports 177 Management Information System (MIS) 151, 157 Mandated restructuring 103 Manufacturers of electrical equipment 11 Manufacturers and natural gas 23 Marina Energy 200 Market 132 Market participants 231 Market-based economies 109 Market-driven managerial leadership 3 Marketing 128, 132, 143, 223 activities 135 and branding 137 expenditures 130 in the utility industry 130, 138 funds 127 management 136 managers 136 objectives 142 plan 136 problems 146 programs 141 Maryland 141, 190, 249 Maryland Colony 5 Mason County, Washington 81 Mason County Public Utility District No. 3 xvi, 80, 81, 158 Massachusetts 6, 219, 249, 284 Massachusetts Bay Company 5 Massachusetts operations center 267 McCord Air Force Base 133 MegaNOPR 28 Mega-Notice of Proposed Rulemaking (MegaNOPR) 28 Megatrends 284 Melting glaciers 287 Merchandising 7 Merchant power generating firm Cinergy 156 Mesopotamia 11, 209, 252 Metered water sales 178 Mexico 226, 227, 228, 248, 282 Mexico’s Comisión Federal de Electricidad (CFE) 227 Michigan 7, 219, 247
341
Microsoft® Excel™ 139 Mid-America Interconnected Networks 142 Mid-Atlantic Area Council 142 Mid-Continent Area Power Pool 142 Middlesex Water 191 Midstream activities 238, 250 Midwestern states 10, 24, 61 Millennium Account Services 200 Million British Thermal Units (MBTUs) 241 Minimum requirements for the system of accounts 169 Minnesota 7, 83, 239, 245, 246 Misconduct 43 Mission of the organization 20 Mission statement 76, 77 Mississippi 7, 239, 287 Missouri 239 Modern information system 157 Modern integrated information 161 Monitoring 220 Monopolies 17 Monopolies and trusts 14 Monopolistic conditions 55 Monopolistic tightly regulated utilities 220 Montana 258 Morality 43, 45, 48, 52 Mormon community water projects 257 Mormon systems 257 Mormons 256 Municipal and investor-owned utilities xi governments 202, 215 industrial development xi owners 8, 272 systems 8, 204, 254, 263 utility 158, 176, 222 water and sewer utilities 204 water and wastewater systems 262 Municipal-employee labor unions 191 Municipalities 202, 203, 215 Municipally controlled system 253 Municipally owned and operated utilities 94, 176, 186, 229 Munn and Scott 10 Munn v. Illinois, 1877 10, 23, 203 Mutual societies 208
342
Subject Index
Mutual society form of utility governance 206 Mutual water companies 257 Nation’s railroads 22 National Association of Regulatory Utility Commissioners (NARUC) 35, 168, 169, 170, 172, 176, 179, 181 National Commission on Energy Policy (NCEP) 277, 280 National Council on Government Accounting 176 National Energy Policy Act (NEPA) of 1992 220, 229, 234, 235 National Grange of the Patrons of Husbandry 24 National grid 220 National health standards for drinking water 259 National Infrastructure Protection Center 106 National interest electric transmission corridors 33 National postal system 7 National Regulatory Research Institute (NRRI) 35–6, 61, 123 Native American tribes 213, 256, 258 Natural gas 11, 12, 14, 32, 222, 225, 240, 242, 251, 272 Natural Gas Act of 1938 (NGA) 26, 27, 30, 57, 62, 63, 70, 242–3 Natural gas xi and electricity utilities 123, 126 and water shortages 3 distribution 86, 239 fueled cogeneration 241 holding companies 238 industry 237, 238, 250, 289 industry faced chronic supply shortages 242, 251 managers 246, 251 Natural Gas Monthly 246 policy 28 producers 247, 248 gas use 281 utilities 138 Natural Gas Policy Act (NGPA) 27, 30, 37, 63, 244, 251
Natural Gas Wellhead Decontrol Act of 1989 28, 64 Natural monopolies 3, 14, 22, 54, 69, 199, 215, 231 Nature of the power industry 271 Nebraska 202 Needed changes to the CIS 157 Negative public opinion 104 Negotiating labor contracts 189, 195 Negotiations 189 Negotiators for the union 189 Net decline in public ownership 204 Netherlands 192 Network model 212, 213, 215 Network of municipal utilities 212 Network security managers 106 Network-expansion experience 158 Nevada 155 New Brunswick Electrical Power Company 103 New Brunswick, Canada 153 New coal-fired generators 226 New Deal 56, 57, 234 New Deal legislation 204, 205 New Deal’s rural electrification program 57 New England 61, 248 New government-mandated environmental control measures 105 New Hampshire 284 New Jersey 40, 191, 200, 219 New Mexico 206, 239, 242, 256, 287 New Mexico Environment Dept. 2003 266 New Mexico State University 227 New Nuclear plants 273 New Public Management (NPM) xii, xiii, xv, 15–6, 33, 94, 107 New regulatory environment 125 New World 4, 5, 6 New York 9, 11, 23, 59, 61, 98, 219, 244, 254, 262 New York Mercantile Exchange (NYMEX) 28 New York State Power Authority (NYSPA) 202 New York Times 40 New York’s Suffolk County 284
Subject Index New Zealand xii, 16, 3, 35, 94, Newark, NJ 185 New-contract negotiations 189 Nice, France 263 Nigeria 249 Nineteenth century 7, 8, 254 No pay, no service model 20 Noncompliance of a single rule 283 Nongovernmental organizations 283 Non-hydroelectric renewables 225 Non-OPEC countries 249 Non-optional necessities 124 Non-peak period supply 131 Nonprofit trusts function 205 Non-regulated power generator 166 Non-regulated power marketing 221 Non-regulated power marketing and trading field 234 Non-utilities 30 North America 4, 5, 11, 130, 142, 143, 197, 198, 209, 227, 235, 249, 272, 273, 275, 276, 287 North American Electric Reliability Council (NAERC) 142, 143, 235 North American Electric Reliability Council regions 228 North American electricity systems 272, 275 North American grids 227 merchant traders 6 natural gas reserves 248 power system (Connor 2002) 271 production fields 237, 250 wholesale market 230 North Carolina 138 North Dakota 206, 207 Northeast United States 63, 197, 231, 279, 282 Northeast blackout 21, 228, 271 Northeast Power Coordinating Council 142 Northern California 258 Northern Illinois energy market 192 Northern Maine 103 Northern Maine and New Brunswick, Canada 153 Northern states 9 Northwest 231 Northwest Territory 7
343
Northwest’s electric power grid 106 Norway xii Not in my backyard (NIMBY) 14 Nuclear generation 274, 288 Nuclear plants 225–6, 273 Nuclear power issue 271 Nuclear Steam Supply System 275 October of 1929 15, 21 Office of the President of the United States 39 Offshore gas 63 Off-System Operations 200 Ogallala Aquifer 287 Ohio 7, 219 Ohio grid operator 219 Ohio State University 123 Oil Pollution Act of 1990 283 Oklahoma 202, 237, 239, 250 Oligopolistic environment 7 Olympia, Washington 81, 255 Oman 249 Onshore new gas 63 Ontario, Canada 78, 219 OPEC cartel 233 Open Access Same-time Information System (OASIS) 230 Open-access, public fiber-optic telecommunication system 158 Operating costs 112, 224 Operational excellence 185 Opponents of restructuring in the industry 232 Option to specify purchase blocks of energy 122 Orange County, California xi Order 2000 31, 230, 236 Order 436 27, 244 Order 451 244 Order 500 244 Order 636 28, 243–4, 251 Order 637 28 Order 888 31, 61, 229, 230, 235 Order 889 31, 61, 235 Ordinance of 1787 6 Oregon 155, 222, 276, 284 Oregon state law 222 Organization’s objectives 76 Organizational cooperation 211 Organizational policy 20
344
Subject Index
Organize data 148 Outer Continental Shelf Lands Act (OCSLA) 27 Outsourcing 198, 269 Overall consolidation 271 Overhead expenses 111–12 Overloads 220 Overpricing 55 Overseas imports 248 Oversight control 228 Overview of the role of public policy xiii Pacific Northwest 157, 177, 198, 202 Pacific Northwest’s Columbia River Basin 276 Pacific Northwest Partnership for Regional Infrastructure Security (PNPRIS) 106 Paradigm shift 3 Paris, France 263 Particularity of electricity 220 Asia 130, 143 Passage of the Fuel Use Act 63 Patrons of Husbandry (Grangers) 10 Payment/financial aid model 20 Peak load 112, 126 Peak-load conditions 158 PECO Energy, Inc 191, 192 Pennsylvania 5, 6, 9, 219, 247, Pentagon 262 People’s Energy, Chicago, Illinois 154 PERCO Energy of Philadelphia 192 Performance standards 190 Periodic outbreaks of illnesses 254, 268 Permits for transmission line construction in the corridors 33 Personnel functions 191 Persuasive control techniques 191 Petroleum-based energy shocks 142 Philadelphia 192, 252, 254 Phillips Petroleum v. Wisconsin 347 U.S. 672 27 Phoenix, Arizona 84 Photovoltaic systems 226 Physical environment model 21 Pierce County 81 Pinnacle West Capital Corporation (Pinnacle West) 84–5 Pipelines 25, 123
Pivotal Virtues 49 PJM (Pennsylvania, New Jersey, Maryland) 61 Planning activity 136 and control purposes 179 in public utilities 89 Platts global energy 2004 27 Policies and practices 193 Policy of restructuring utilities 33 Policy shifts 95 Policymakers 34 Policymakers and utility managers 277 Political rights 47 Population of the United States 8 Port of New York 9 Port of Seattle 106 Port of Shelton 213 Portfolio manager 278 Portland, Oregon 276 Porto, Portugal (1882) 263 Potable water 259 Potential customers 131 Power crisis 166 Power markets 96, 226 Power Markets Week 138 Power Plant and Industrial Fuel Use Act (PPIFU) 30 Power Plant and Industrial Fuel Use Act 37 Power production 209 Power shortages 129, 276 Predicted load (demand) 133 Preparedness strategies 106 President’s Global Climate Change Initiative 283 Price breaks 122 Price discrimination 13 Price of natural gas 273 Price of producing utility products 128 Price run-ups 42 Pricing decisions 117 Principal process of a customer relationship program 157 Private companies were granted licenses 11 Private contractor 191, 197 Private Corporation 252 Private generators in California 42 Private ownership 24, 210 Private Sector 161
Subject Index Private Securities Litigation Reform Act of 1995 74 Private system operators 253 Private transmission and distribution facilities 33 Private utilities 3, 8, 199, 215, 169 Privately developed infrastructure 4 Privately financed railroads and utility services 24 Privately owned grain elevators 204 Privatization 39 Privatization and deregulation movements xii, 3, 182 Privatization model 35 Privatization of complete systems 35 Privatized utility model 208 Process of setting prices in distribution public utilities 110, 125 Processed data 148 Product planning 136 Product tampering 105 Production problems 146 Production, transmission, and distribution 3, 32 Professional/technical unity 185 Profile of a public utility district 81 Program evaluation 3 Programs function at four organization levels 185 Progressive Era 14, 17, 19, 24, 37, 196, 204, 215 Proper data storage 148 Protection One Europe 79 Prototype recommendations 278 Providing equality of opportunity 193 Provisions in the Ordinance of 1787 10 Public agencies in the 1930s 202 Public and investor-owned organizations 165 Public and private municipal water systems 256 Public/Private Partnerships (PPPs) 3, 265 Public authority 92, 208 Public Health and Bioterrorism Preparedness and Response Act 266 Public Health Security 286, 289
345
Public interest companies 206 Public management 41, 92, 107 Public opinion 93 Public ownership 15, 24, 203, 298–9 Public Policy 1, 19, 36, 93 Public rail 11 Public Safety policies 19 Public sector 272 Public service 3, 203 Public transportation xi Public utilities 12 Public Utilities Division 56 Public Utilities Fortnightly 155, 183 Public Utility Commission (PUC) 55, 67, 75, 103, 118, 125, 231–2, 244 approval 42 regulators 42 established rate of return utilities 67 Public Utility District No. 1 (PUD) 77, 213 Public Utility Districts (PUDs) 197, 229, 276 Public utility finance officers 163 Public Utility Holding Company Act of 1935 (PUCHA) 26, 36, 37, 56, 69, 201, 205, 211, 230, 238 Public Utilities in American Capitalism 145 Public utility industry xiii, 9, 145, 182, 288 Public utility management 94 Public utility management and governance 211 Public utility managers 121, 126, 180 Public utility price schedules 120 Public Utility Regulatory Policies Act (PURPA) 30, 31, 59, 60, 67, 69, 229, 232, 233 Public Utility Regulatory Policies Act of 1978 37, 69, 229, 235 Public versus investor-owned public utilities 44 Public warehouses 12 Publicly owned utilities 158, 168, 189, 210, 269 Publicly owned utility finance managers 177 Puerto Rico 263, 282 Puget Sound Energy 106
346
Subject Index
Pumped storage 225 Pumping 25 Purchased costs of gas 244 PURPA regulations 166 Purpose of information technology 146 Purpose of the retained earnings accounts 175 Purpose of the vulnerability assessment 286 Purposes of the BASB 168 Qatar 249 Quakers 5 Qualifying facility (QF) 60, 67 Quality problems 146 Quasi-governmental institutions 208 Qwest 106 R.W.Beck Company 1998 survey 265 Radical change 220 Railroads 22–3 Rate of return (ROR) 245 Rate-base changes 271 Ratemaking process 188 Rates and prices 111 Rates established for publicly owned utilities 116 Rationale for regulation of business activities 54 Rationale for utility regulation xiv Real-time metering 121, 134 Reasonable operating expenses 116 Rebates or discounts 122 Reclamation Act of 1902 258 Reclamation Act of 1906 209 Record-keeping 168 Records Center Manager xvi Reduce power plant emissions 83 Reform of the traditional merit system 187 Regional Transmission Organization (RTO) 31, 61, 230, 236, 276 Regional transmission territories 61 Regulated investor-owned utilities 220 Regulated market 133 Regulated utilities 13, 17 Regulation 6 at the state level 102
of the gas industry 243 policy 75 Regulators and boards of consumerowned utilities 279 Regulatory action taken 21 and corporate governance xv changes 196 Commission 280 Orders 888 and 889 31 Reinventing Government 93 Reliability Council 228, 235 Reliant Resources 239 Renewable energy portfolio 83 Renewable resources 225 Reorganization 97, 182 Reorganization and restructuring 97 Repeal of the PUHCA 201 Republic of Mexico 227 Reservoirs 14, 247 Residential customers 131, 143, 241, 251 Residential market 242 Residential retail competition 232 Resource Conservation and recovery Act 283 Resources Group 200 Response Act of 2002 286, 289 Restructuring 28–9, 34, 98, 125, 197, 234, 237, 246 Restructuring Office 98 Resultant heavy price 288 Retail competition 222, 245 distribution of electricity 278 level 130, 143 marketing 132, 135, 278 operations 221 organizations 136 sales 135 unbundling 237 Retained earnings accounts 170 Retained revenues 165 Retirement benefits 185, 195 Retirement plans 185, 195 Retrenchment for deregulation and competition 138 Retributive justice 48 Revenue requirements 109 Reversal of restructuring 289 Revised SMD proposal 230
Subject Index Revolution in transportation 7 Rhode Island 11 Richmond, Virginia 134 Riga, Latvia xii, xvi Rights Ethics 47 Right of a city-owned utility to operate 209 Right to purchase gas 247 Rio Grande Power Station 241, 242 Rising costs of natural gas 271 Riverboat 4 Rochester Natural Gas Light Company 11 Rochester, New York 11 Rocky Mountain 227 Rocky Mountain region 227, 282 Rolling blackouts 131, 271 Rolling brownouts 1 Roman Empire 11, 209 Routine maintenance 284 Royal charter in 1681 5 Rural Electrification Act in 1936 26 Rush Electric Company 23 Safe Drinking Water Act of 1974 (SDWA) 29, 65–6, 70, 259–60, 266, 268, 283, 286 San Diego, etc. v. Jasper (74 Fed. 79, 83) 117 San Francisco, California 254 San Francisco Chronicle 40 San Jose, California 185 Sanitation 11 Santa Cruz River 288 Santee-Cooper Project 202 SAP, (ERP software company) 153 Savannah, Georgia 249 Scale and scope of the public utilities industry xiii Scandal 182 Schedules of prices 125 Scotland 208 Seattle, Washington 14, 197 Second generation rights 47 Second set of primary balance sheet accounts 171 Second water system 252 Secretary of the Interior 209 Securities and Exchange Act of 1934 37, 56, 69, 196
347
Securities and Exchange Commission (SEC) 56, 59, 69, 102, 16–9, 201, 212 Sherman Antitrust Act of 1890 196 September 11, 2001 104, 217, 262, 286 Service Order Entry System (SOES) 159, 160 SH EnerTrade 200 Shallow Gulf Coast fields 237 Shelton, Washington xvii, 213–4 interorganization agreement 214 Shifting to natural gas 284 Shocks 221 Shortages 63 Short-term growth 241 Shrinking workforce 184 Simple information management system (IMS) 145 Singapore 192 Site clean-up requirements 83 Site limitations 14 Skill in analysis 96 Smyth v. Ames (169 US 486) 118 Social capital 12 Social environmental constraints 104 Social pricing consideration 122 Socialist economies 94 Society and the power generation sector 279 Solid waste disposal 14 South America 197 South Carolina 202 South Jersey Energy Company (SJE) 200 South Jersey Gas 200 South Jersey Industries, Inc. (SJI) 200 South Jersey Resources Group 200 Southeast Arizona 288 Southeastern U.S. 231, 276 Southeastern Electric Reliability Council 142 Southeastern Pennsylvania 192 Southern California 96, 258 Southern California Metropolitan Water District 257 Southern New Mexico 227 Southwest 256, 261 Southwest Power Pool 142 Soviet block of nations 94
348
Subject Index
Spanish acwqyas 257 Spate of mergers 234 Species extinction 83 Specific services 11 Spike in the price of natural gas 274 Spoils system 9 Spokane, Washington 154, 276 Spot market 130, 133 Spot price 241 Sri Lanka 124 St. Lawrence River 7 St. Lawrence River Project 202 Standard & Poor’s 240–41 Standard gas turbines 224 Standard Market Design (SMD) 36, 61, 62, 230, 231 Standard operating procedures 180 State and federal fish and wildlife agencies 213 State Department of Ecology 255 State Department of Licensing 41 State governments 202, 215 State laws 127 State legislatures 24 State or local regulators 115 State Patrol’s Training Academy (Washington) 213 State public utility commissions 116, 120, 125, 126, 170 State PUC regulators 42 State regulations 67, 83, 220, 231, 244 State Water Pollution Control Revolving Fund 66, 259 State-approved Urban Development Area 213 Statement of earnings invested in the business 175 Statements of governmental accounting standards No. 34 (AICPA) 177 States of nature 139 Step rate pricing 119 Stock market crash of 1929 101, 196 Stockholders 257 Stockholm School of Economics xi Storage facilities 12 Storing of natural gas 25, 247 Stranded costs 231 Strategic approach to management xiii, 97
gaps 139 management xiii, 76, 89 marketing plan 136 objectives and policy formulation 73 planning 3, 73, 82 Street traction 25 Suffolk County 284 Sunk costs 115, 229, 231 Supervisors 185 Supervisory Control and Data Acquisition (SCASA) system 158, 279 Supply chain 249 Supranet 150 Supreme Court cases 10 Sweden xii, 16, 94 SWOT Analysis 73, 74 System failure 182 System inputs 111 System of accounts 170 System of governance 223 Systematic assessment of the operation 87 Tacoma, Washington 133, 153, 158, 186, 187, 197 Public Utilities 133 Employees’ Retirement System 187 Power 159, 187 Rail 187 Utilities 153, 187 Water 187 Take-or-pay contracts 27 Tampa Bay Water 75, 262 Technological advances 226 Technologies and fuels 223, 235 Tehachapi Mountains 258 Tele-communications 23 Telecommunications xi Telephones 23 Telus Corp. 106 Tennessee River watershed 276 Tennessee Valley Authority (TVA) 26, 34, 37, 57, 61, 94, 136, 204, 209, 222, 276 Terrorists’ attacks 286 Texas Commission on Environmental Quality 227 Texas 202, 220, 221, 227, 237, 239, 242, 247, 250, 257, 258
Subject Index grid 227 Interconnected System 227–8, 235 based energy trading company 138 based, third-party company 41 The Bonneville Power Administration Act of 1937 210 The Federal Energy Regulatory Commission (FERC) 238 Thomson-Houston Electric Company 23 Three major transmission grids or interties 235 Tight sands 282 Time series analysis 139 Title IV 266 Tobago 249 Toll roads 4 Topeka, Kansas 79 Total cost of the operating system 111 Total load (demand) 139 Total Maximum Daily Loads (TMBLs) 65, 259 Total Quality Management (TQM) 95 Touchstone Energy 207 Trading and Exchange Division 56 Traditional responsibilities of state utility commissions 123 Traditional public utility industries 23, 107 Transaction processing systems (TPS) 152 Transactional process 192 Transfer stations 14 Transfers between the utility and other funds of the municipality 176 Transformers 226, 235 Transition costs 229 Transition years 22 Transmission 32, 143, 226, 235 and distribution services 32 grid 220, 235 lines 25, 271 operators 125 owners 229 system 35, 61, 220 Transportation costs 246 Transportation industry 251 Treatment services 30 Trends facing the water and wastewater industry 289
349
Trinidad 249 TUI Consulting 153 Turn-pikes and waterways 6 Two-way goal setting 140 Typical or average demand level 139 Unbundling 31, 98, 115, 129, 135, 229, 230 Unconventional sources 282 Under-investment 272 Underground storage facilities 247 Uneconomic over-expansion and resource misallocation 210 Unethical behavior 182 Unicom 192 Uniform systems of accounts 169 Union contracts 188, 195 Union management relations 195 United Kingdom 3, 192, 208 United States Senate 40 United States (US) xiii, 3, 7, 9, 10, 11, 14, 61, 68, 70, 75, 80, 84, 92, 107, 142, 143, 191–2, 194, 197, 198, 202–204, 208, 214, 219, 221, 223, 225, 235, 239, 241, 243, 247–9, 252–3, 256, 261, 268, 273, 274, 276, 282, 287, 289 Army Corps of Engineers 258 Civil War 257 Congressional investigators 40 Dept. of Energy 2005 281 Electrical power industry xii Electricity 225 Environmental Protection Agency (EPA) 66, 254 Fish and Wildlife Service 83 generating capacity 223 greenhouse gas intensity (GGI) 283 imports of LNG 282 investor-owned utilities 226 mercury emissions 284 nuclear construction industry 273 Unregulated affiliates 141 Unregulated market 133, 134 Unregulated retail energy market 138 Unregulated transmitting utilities 33 Upstream activities 238, 250 U.S. Navy 106 auxiliary airport 213
350
Subject Index
Utility Business Architecture (UBA) 147 Utility Comunications Architecture (UCA) 147 Urban areas 198 Urbanization 29 US Department of Energy (DOE) 232 Utah 257, 258 Utilitarian ethics 46 Utilities 288 as economic organizations 13 income 13 wholesale and retail markets 132 Utility industry 31, 102, 141, 142, 196 accounting decisions 164, 181 business 127, 142, 154 business architecture (UBA) 147 commissions 244 communication architecture (UCA) 147 costs 131 deregulation 68 forecasting 96 governance functions and models 215 holding companies 58, 135 industry restructuring actions 33 infrastructure 25 managers 77, 95, 104, 105, 112–3, 118, 125–6, 167, 188, 265, 283, marketing 140 networks 32 planning 97 policy in the United States 30 products 136 rate base 118 rate schedules 122 reform movement 15, 17 regulation 55, 68, 69, 70, 123 restructuring and privatization 205 workers 181, 188 Utility’s chief resources 90 Utility’s service load 131, 143 Utilization of the system 115 Valuation of the assets of the utility 116 Value of the utility 106 Veolia Environment 263 Verizon 106
Vermont 219 Vertical integration 234 Vertically integrated utility (VIU) 115, 125, 164, 166, 180, 236 Vices 49 Virginia 141, 190 Virginia Company 5 Virtue Ethics 49 Visual pollution 83 Vivendi 263 Vulnerability assessment 286 Vulnerability of the nation’s utility networks 106 Wall Street Crash of 1929 57 Washington Gas 190 Washington Gas Light Company 141 Washington State 40–41, 197 Department of Corrections 213 Washington Utilities and Transportation Commission xvi Washington, D.C. 74, 86, 141 Waste disposal 11 Wastewater Industries 262 Wastewater xi Water 11, 252 and sanitation 23 and sanitation utility network systems 35 and wastewater sectors xi and wastewater systems 252 and wastewater utility managers 262 districts 258 policies 19 pollution 83, 283 standards 66, 260 treatment plants 25 utilities 260, 284 utility industry 29 utility response 266 Water Power Act of 1920 205 Weather risk 141 Welfare policies 19 Wenatchee, Washington 185 West and Northwestern Sections of the country 225 West Coast 276 West Coast of California 282 West Texas 227
Subject Index Westar Energy of Topeka 79 Western and Texas interconnects 227 Western Area Energy Administration 88 Western Canada 227 Western economic system 47 Western Energy Services 2003 88 Western Hemisphere 252 Western Interconnected Grid 227, 235 Western United States 16, 39, 206, 255, 257, 258, 287–8 Western Systems Coordinating Council 142 Western Union 23 Westinghouse Electric 273 WGEServices 141 WGL Holdings, Inc. 74, 86, 141, 190 Wheeler-Rayburn Act 102 Wholesale energy merchant 240, 250
351
Wholesale level 132–3, 143 Wholesale power market platform 230 Wholesale price of energy or water increases 131 Wholesale price run-up 42 William Penn’s Free Society of Traders 5 Williams Gas Pipeline 106 Wipro Technologies 156–7 Wisconsin 7, 239 World Bank 16 World Trade Center 262 World War I 204 World War II 26 Wyoming 66, 207 XCEL Energy 83 Zone rates 120
