Understanding Electric Power Systems E-Book

Frank Delea

• Herausgeber: John Wiley & Sons
• Kategorie: Wissenschaft und neue Technologien
• Serie: IEEE Press Understanding Science & Technology Series
• Sprache: Englisch

Seitenzahl: 455

Veröffentlichungsjahr: 2011

Beschreibung

A COMPREHENSIVE LOOK IN LAYMAN'S TERMS AT THE MANY ASPECTS OF THE PROVISION OF ELECTRIC POWER, BY TWO VETERAN EXECUTIVES AND RESPECTED EXPERTS

Technological advances and changes in government policy and regulation have altered the electric power industry in recent years and will continue to impact it for quite some time. Fully updated with the latest changes to regulation, structure, and technology, this new edition of Understanding Electric Power Systems offers a real-world view of the industry, explaining how it operates, how it is structured, and how electricity is regulated and priced. It includes extensive references for the reader and will be especially useful to lawyers, government officials, regulators, engineers, and students, as well as the general public.

The book explains the physical functioning of electric power systems, the electric power business in today's environment, and the related institutions, including recent changes in the roles of the Federal Energy Regulatory Commission and the North American Reliability Company. Significant changes that are affecting the industry are covered in this new edition, including:

• The expanded role of the federal government in the planning and operation of the nation's electric utilities
• New energy laws and a large number of FERC regulations implementing these laws
• Concerns over global warming and potential impacts on the electric industry
• Pressures for expansion of the electric grid and the implementation of "smart-grid" technologies
• The growing importance of various energy-storage technologies and renewable energy sources
• New nuclear generation technologies
• The 2009 economic stimulus package

Leseprobe

CONTENTS

PREFACE TO THE SECOND EDITION

ACKNOWLEDGMENTS

CHAPTER 1 BENEFITS OF ELECTRIC POWER AND A HISTORY OF THE ELECTRIC POWER INDUSTRY

1.1 SOCIETAL BENEFITS OF ELECTRICITY

1.2 ORIGIN OF THE INDUSTRY

1.3 THE DEVELOPMENT OF THE NATIONAL ELECTRIC POWER GRID

1.4 “THE GOLDEN AGE”

1.5 GLOBAL WARMING CRISIS AND CONCERNS ABOUT CARBON EMISSIONS

1.6 RESTRUCTURING, COMPETITION, AND THE INDUSTRY OWNERSHIP STRUCTURE

CHAPTER 2 THE ELECTRIC POWER SYSTEM

2.1 THE CUSTOMERS

2.2 SOURCES OF THE ELECTRIC ENERGY—GENERATION

2.3 THE DELIVERY SYSTEM

CHAPTER 3 BASIC ELECTRIC POWER CONCEPTS

3.1 ELECTRIC ENERGY

3.2 CONCEPTS RELATING TO THE FLOW OF ELECTRICITY

3.3 CHARACTERISTICS OF AC SYSTEMS

3.4 OHM’S LAW FOR ALTERNATING CURRENT

3.5 POWER IN ALTERNATING CURRENT CIRCUITS

3.6 POWER FLOW

3.7 STABILITY

CHAPTER 4 ELECTRIC ENERGY CONSUMPTION

4.1 END USES FOR ELECTRICITY

4.2 CUSTOMER CLASSES

4.3 RATE CLASSES

4.4 DEMAND AND ENERGY

4.5 SYSTEM LOAD

4.6 REACTIVE LOAD

4.7 LOSSES AND UNACCOUNTED-FOR ENERGY IN THE DELIVERY SYSTEM

4.8 FORECASTS

CHAPTER 5 ELECTRIC POWER GENERATION AND CONCERNS ABOUT GREENHOUSE GASES

5.1 GENERATION’S ROLE

5.2 TYPES OF GENERATION

5.3 THERMAL CONVERSION: USING FUEL AS THE ENERGY RESOURCE

5.4 THERMAL CONVERSION: NONFUEL HEAT SOURCES

5.5 MECHANICAL ENERGY CONVERSION

5.6 RENEWABLE TECHNOLOGIES AND GREENHOUSE GAS EMISSIONS

5.7 CHARACTERISTICS OF GENERATING PLANTS

5.8 CAPITAL COST OF GENERATION

5.9 GENERATOR LIFE EXTENSION

5.10 THE TECHNOLOGY OF GENERATION

5.11 SYSTEM NEEDS AND EVALUATION OF INTERMITTENT RESOURCES

CHAPTER 6 THE TECHNOLOGY OF THE ELECTRIC TRANSMISSION SYSTEM

6.1 COMPONENTS

6.2 HVAC

6.3 SUBSTATIONS

6.4 HVDC

6.5 ADVANTAGES OF AC OVER DC OPERATION

6.6 KNOWLEDGE REQUIRED OF TRANSMISSION SYSTEMS

CHAPTER 7 DISTRIBUTION

7.1 FUNCTION OF DISTRIBUTION

7.2 PRIMARY DISTRIBUTION FEEDERS

7.3 DISTRIBUTION CAPACITY

7.4 LOSSES

7.5 DISTRIBUTION FACILITY RATINGS

7.6 METERING

7.7 CONTROL OF DISTRIBUTION VOLTAGES

7.8 DISTRIBUTION SYSTEM RELIABILITY

7.10 QUALITY OF SERVICE

7.11 DESIGN OF DISTRIBUTION SYSTEMS

7.12 DISTRIBUTED GENERATION

7.13 OPERATION OF DISTRIBUTION SYSTEMS

7.14 SMART GRIDS AND MICROGRIDS

CHAPTER 8 ENERGY STORAGE AND OTHER NEW TECHNOLOGIES

8.1 ENERGY STORAGE

8.2 ENERGY STORAGE CONCEPTS AND TECHNOLOGIES

8.3 SMART GRID

8.4 NEW NUCLEAR PLANT DESIGNS

8.5 CARBON SEQUESTRATION AND CLEAN COAL TECHNOLOGIES

8.6 SUPERCONDUCTORS

CHAPTER 9 RELIABILITY

9.1 CAUSES OF OUTAGES

9.2 COSTS OF POWER OUTAGES

9.3 WAYS TO MEASURE RELIABILITY

9.4 PLANNING AND OPERATING A RELIABLE AND ADEQUATE POWER SYSTEM

9.5 SUMMARY

CHAPTER 10 THE PHYSICAL NETWORK: THE NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION (NERC) AND ITS STANDARDS

10.1 NERC AS ELECTRIC RELIABILITY ORGANIZATION

10.2 NERC STANDARDS

10.3 DEVELOPMENT OF STANDARDS

CHAPTER 11 THE PHYSICAL NETWORK: OPERATION OF THE ELECTRIC BULK POWER SYSTEM

11.1 BALANCING AUTHORITIES

11.2 RELIABILITY COORDINATORS

11.3 TRANSMISSION OPERATORS

11.4 VOLTAGE AND REACTIVE CONTROL

11.5 EMERGENCIES

11.6 INFORMATION EXCHANGE

CHAPTER 12 THE PHYSICAL NETWORK: PLANNING OF THE ELECTRIC BULK POWER SYSTEM

12.1 PLANNING STANDARDS

12.2 GENERATION PLANNING

12.3 TRANSMISSION PLANNING

12.4 LEAST COST PLANNING

12.5 THE NEW PLANNING ENVIRONMENT

CHAPTER 13 THE REGULATORY NETWORK: LEGISLATION

13.1 PRICING AND REGULATION

13.2 FEDERAL LEGISLATION

13.3 FEDERAL UTILITY HOLDING COMPANY ACT (PUHCA)

13.4 FEDERAL POWER ACT

13.5 OTHER 1930 FEDERAL LAWS

13.6 DEPARTMENT OF ENERGY ORGANIZATION ACT

13.7 PUBLIC UTILITY REGULATORY POLICIES ACT (PURPA)

13.8 ENERGY POLICY ACT OF 1992 (EPACT02)

13.9 THE ENERGY POLICY ACT OF 2005 (EPAct05)

13.10 THE ENERGY INDEPENDENCE AND SECURITY ACT OF 2007

13.11 ENVIRONMENTAL LAWS

13.12 2009 AMERICAN RECOVERY AND REINVESTMENT ACT

CHAPTER 14 THE REGULATORY NETWORK: THE REGULATORS

14.1 THE REGULATORS

CHAPTER 15 THE INFORMATION, COMMUNICATION, AND CONTROL NETWORK AND SECURITY

15.1 SMART GRID

15.2 FINANCIAL AND BUSINESS OPERATIONS

15.3 SYSTEM OPERATIONS

15.4 DISTRIBUTION OPERATIONS

15.5 CYBER SECURITY

15.6 NUCLEAR PLANT SECURITY

CHAPTER 16 THE FUEL AND ENERGY NETWORK

16.1 RESOURCE PROCUREMENT

16.2 FUEL TRANSPORTATION

16.3 FUEL DIVERSITY

16.4 FOSSIL FUELS USED

16.5 RENEWABLE ENERGY

16.6 FUEL PURCHASING

16.7 EMISSION RIGHTS

CHAPTER 17 THE BUSINESS NETWORK: MARKET PARTICIPANTS

17.1 INVESTMENT AND COST RECOVERY

17.2 THE CHANGING INDUSTRY STRUCTURE

17.3 NEW STRUCTURES

17.4 NEW CORPORATE OWNERSHIP

CHAPTER 18 THE MONEY NETWORK: WHOLESALE MARKETS

18.1 THE ENERGY MARKETS

18.2 TRANSMISSION

18.3 CUSTOMER RATE ISSUES

18.4 MARKET VERSUS OPERATIONAL CONTROL

18.5 MARKET POWER ISSUES

18.6 THE FUTURE

CHAPTER 19 THE PROFESSIONAL AND INDUSTRY ORGANIZATIONS

19.1 THE PROFESSIONAL ORGANIZATIONS

19.2 INDUSTRY ASSOCIATIONS

19.3 PUBLIC INTEREST GROUPS

19.4 RESEARCH ORGANIZATIONS

INDEX

IEEE PRESS Understanding Science & Technology Series

The IEEE PRESS Understanding Series treats important topics in science and technology in a simple and easy-to-understand manner. Designed expressly for the non-specialist engineer, scientist, or technician as well as the technologically curious— each volume stresses practical information over mathematical theorems and complicated derivations.

Other books in the series include:

Understanding the Nervous System An Engineering Perspective

by Sid Deutsch, Visiting Professor, University of South Florida, Tampa and Alice Deutsch, President, Bioscreen, Inc., New York

1993 Softcover 408 pp ISBN 0-87942-296-3

Understanding Telecommunications and Lightwave Systems An Entry-Level Guide

by John G. Nellist, Consultants, Sarita Enterprises Ltd.

1992 Softcover 200 pp ISBN 0-7803-0418-7

Tele-Visionaries The People Behind the Invention of Television

by Richard C. Webb

2005 184 pp ISBN 978-0471-71156

Understanding Lasers: An Entry-Level Guide

by Jeff Hecht, Science Writer and Editor, Auburndale, Massachusetts

2008 494 pp ISBN 978-0470-08890-6

Understanding Electric Power Systems: An Overview of the Technology, the Marketplace, and Governmental Regulation, Second Edition

by Jack Casazza and Frank Delea

2010 340 pp ISBN 978-0470-48418-0

IEEE Press

445 Hoes Lane Piscataway, NJ 08855

IEEE Press Editorial Board

Lajos Hanzo, Editor in Chief

R. Abari

T. Chen

B. M. Hammerli

J. Anderson

T. G. Croda

O. Malik

S. Basu

M. El-Hawary

S. Nahavandi

A. Chatterjee

S. Farshchi

W. Reeve

Kenneth Moore, Director of IEEE Book and Information Services (BIS)

Copyright © 2010 by the Institute of Electrical and Electronics Engineers, Inc.

Published by John Wiley & Sons, Inc., Hoboken, New Jersey. All rights reserved. Published simultaneously in Canada.

No part of this publication may be reproduced, stored in a retrieval system or transmitted in any form or by any means, electronic, mechanical, photocopying, recording, scanning or otherwise, except as permitted under Section 107 or 108 of the 1976 United States Copyright Act, without either the prior written permission of the Publisher, or authorization through payment of the appropriate per-copy fee to the Copyright Clearance Center, Inc., 222 Rosewood Drive, Danvers, MA 01923, [phone], fax [phone], or on the web at www.copyright.com. Requests to the Publisher for permission should be addressed to the Permissions Department, John Wiley & Sons, Inc., 111 River Street, Hoboken, NJ 07030, [phone], fax [phone], or online at http://www.wiley.com/go/permission.

Limit of Liability/Disclaimer of Warranty: While the publisher and author have used their best efforts in preparing this book, they make no representation or warranties with respect to the accuracy or completeness of the contents of this book and specifically disclaim any implied warranties of merchantability or fitness for a particular purpose. No warranty may be created or extended by sales representatives or written sales materials. The advice and strategies contained herein may not be suitable for your situation. You should consult with a professional where appropriate. Neither the publisher nor author shall be liable for any loss of profit or any other commercial damages, including but not limited to special, incidental, consequential, or other damages.

For general information on our other products and services please contact our Customer Care Department within the United States at [phone], outside the United States at [phone] or fax [phone].

Wiley also publishes its books in a variety of electronic formats. Some content that appears in print, however, may not be available in electronic formats. For more information about Wiley products, visit our web site at www.wiley.com.

Library of Congress Cataloging-in-Publication Data:

Casazza, John.Understanding electric power systems : an overview of the technology and the marketplace / Jack Casazza, Frank Delea.— 2nd ed. p. cm.Includes bibliographical references.ISBN 978-0-470-48418-0 (pbk.)

1. Electric power systems. 2. Electric utilities. 3. Electric power. I. Delea, Frank. II. Title.TK1001.C386 2010621.319′1—dc222009045958Printed in the United States of America.10 987654321

PREFACE TO THE SECOND EDITION

THIS VOLUME IS THE SECOND edition of a text originally published in 2003. Since its publication, significant changes have, and continue to, impact the electric utility industry including:

The 2003 northeast U.S. blackoutNew energy laws and a large number of FERC regulations implementing these lawsA change in FERC’s role in overseeing the industry’s reliability rules and practicesNERC’s role in establishing these rules and in monitoring complianceThe 2009 Economic Stimulus packageConcerns about global warming and efforts to limit the utility industry’s contribution to greenhouse gases

This edition addresses these issues. As Joseph C. Swidler, former Chairman of the Federal Power Commission [predecessor of the Federal Energy Regulatory Commission (FERC)] often stated: “There are many disagreements about the best electric power policy for the United States, but there is no disagreement [that] it is often being established without adequate analyses.” Government and business decisions on electricity supplies often fail to recognize how power systems work and the uncertainties involved. Those involved do not always mean the same thing although they use identical words. Incorrect assumptions have been made about the operation of the electric system and continue to be made based on the operation of telephone systems, gas systems, and other physical systems that are not applicable to electric power systems.

The purpose of this book is to help those in government, business, educational institutions, and the general public, have a better understanding of electric power systems, institutions, and the electric power business.

The first edition was used for instructional purposes in many courses for electrical engineers who were not power systems engineers, for lawyers, accountants, economists, government officials, and public interest groups. Since its publication, technological and institutional changes have occurred. A major change has been the drastic increase in the government’s role in the electric power industry, changing from emphasis on price regulation to an emphasis on increased control of planning, operation, design, and control of the system and the new technologies being developed. This second edition reflects this and other changes.

In recent years, the U.S. Congress has enacted a series of omnibus energy acts in response to three national imperatives:

1. Establishing a wholesale market for electricity while maintaining a reliable electric supply system

2. Reducing the country’s reliance on imported oil

3. Reducing the country’s contribution to global warming by reducing reliance on carbon-based fuels

The following chapters lay the background for each of the three imperatives in order that the various initiatives might be more clearly seen. We then describe various aspects of these acts and discuss their impacts on the electric power industry, including its regulatory framework, the entities involved, and the technologies used and under development. The difficulty lies in bringing some focus to a moving target. For example, reliability and market issues are being addressed, whereas the underlying structure of the industry remains in flux. Many of the changes relating to the entities involved in the industry are also addressed, including:

New roles for FERC, DOE, and NERCConsolidations of old-line utilities, the newer power marketing companies, RTOs/ISOs, and regional reliability councilsNew ownership interests including investment bankers, foreign investors, venture capitalists, and entrants seeking new business opportunities in generation, transmission, distribution, and customer serviceTrade organizations/lobbying arms that have been started to seek public support of the various entities

The book covers electric power systems, their components (generation, transmission, and distribution) electricity use, electric system operation, control and planning, power system reliability, government regulation, utility rate making, and financial considerations. It is based on the following “seven networks”:

1. Physical

2. Fuel/energy

3. Money

4. Information,

5. Communication and control

6. Regulatory

7. Business

These are all interconnected in the provision of electric power. It provides the reader with an understanding of the equipment involved in providing electric power, the functioning of the electric power system, the factors determining the reliability of service, the factors involved in determining the costs of electric power, and many other technical subjects. It provides the engineer with background on the institutions under which power systems function. It can be used as a classroom text, as well as a reference for consultation. Although a book of this length cannot provide in-depth discussions of many key factors, it is hoped that it provides the broad understanding that is needed.

The Internet has made available many new and valuable publications and information sources that were used in the preparation of this edition. References are provided for those who wish to pursue important points further. The index facilitates the location of background material as needed. We welcome comments, suggestions, additional information, and corrections, and hope you, your company, and all consumers benefit from the book.

Jack Casazza

Frank Delea

Springfield, Virginia

Roswell, Georgia

September 2009

ACKNOWLEDGMENTS

WHEN REVISING A TEXT COVERING the wide range of topics as we have in this book, the assistance of a number of individuals cannot be overstated. We especially want to thank Tom Schneider for his valuable suggestions concerning the organization of this complex and varied material, and for his input relating to generation and storage. Helpful comments and suggestions were also provided on NERC matters by David Nevius of NERC, on FERC matters by Lynn Hargis, on fuel issues by Jim Francher, on T&D issues by Charles L. Rudasill, Jr. (retired from Dominion Virginia Power), and for comments on information technology by Stan Klein. Any errors that may have crept into the text in these areas are solely the responsibility of the authors. We also want to thank Irene Cunnane for her help in assembling the final manuscript.

Above all, we want to acknowledge our wives, Madeline and Irene. Their support, encouragement, and, yes, understanding as we locked ourselves away writing for hours on end was immeasurable.

J. C.

F. D.

CHAPTER 1

BENEFITS OF ELECTRIC POWER AND A HISTORY OF THE ELECTRIC POWER INDUSTRY

1.1 SOCIETAL BENEFITS OF ELECTRICITY

Electric power is one of the mainstays of our lives and the life of our nation. It differentiates advanced societies from third world nations. It touches almost every facet of our lives: our homes, our businesses, our schools, our transportation, and our leisure time. It is there when we are born, and it is there when we die. Think of the impact on our lives if we were not able to watch our favorite TV shows, use our home computers, heat and cool our homes, refrigerate our food, wash our clothes or our dishes, or read at night. Yet most people take it for granted, except during those relatively rare times when it is unavailable or when we receive our electric bills and note that the charges have suddenly and unexplainedly increased.

We know we have power outlets in our homes and businesses and we may notice the distribution wires running along our streets or if we pass high-voltage transmission towers, but many of us do not know how the whole system works. Some of us are affected because we live close to new or proposed electric power facilities, generating plants, or transmission lines and substations. Some may have concerns about the economic or environmental effects of producing electricity.

The National Academy of Engineering has described the de velopment of the national electric power system as the greatest engineering achievement of the 20th century. It has involved legions of electrical, civil, mechanical, nuclear, software, and environmental engineers working for utilities and manufacturers. It also required individuals involved in everything from meter reading, to construction, operation, and maintenance of the power plants and the transmission and distribution lines, and to specialists in accounting, finance, customer relations, public affairs, and even law. Unfortunately, electric power is not a topic covered in our schools and is barely covered in our media. Even individuals who work for utilities may not know the “big picture” outside of their specialties. Decisions are often made about electric power issues with little or no input from the general public and little or no understanding of the technical and economic issues by lawmakers.

The electric industry is large and complex, involving technical, business, and governmental aspects. It cannot be viewed or understood unless one is also familiar with the regulatory environment in which it operates. This book attempts to inform its readers so that they may understand the continuing discussions and debates about the industry and its future and may be able to participate and have their own views heard.

1.2 ORIGIN OF THE INDUSTRY

The electric utility industry can trace its beginnings to the early 1880s. During that period, several companies were formed and installed water-power-driven generation for the operation of arc lights for street lighting, which was the first real application for electricity in the United States. In 1882, Thomas Edison placed into operation the historic Pearl Street steam-electric plant and the pioneer direct current distribution system by which electricity was supplied to the business offices of downtown New York. By the end of 1882, Edison’s company was serving 500 customers that were using more than 10,000 electric lamps. The early Edison systems delivered the electricity by using low-voltage direct current (DC).

Satisfied with the financial and technical results of the New York City operation, licenses were issued by Edison to local businessmen in various communities to organize and operate electric lighting companies.1 By 1884, twenty companies were scattered in communities in Massachusetts, Pennsylvania, and Ohio; in 1885, thirty-one; in 1886, forty-eight; and in 1887, sixty-two. These companies furnished energy for lighting incandescent lamps, and all operated under Edison patents.

Two other achievements occurred in 1882: a water-wheel-driven generator was installed in Appleton, Wisconsin; and the first transmission line was built in Germany to operate at 2400 volts direct current over a distance of 37 miles (59 km).2 Motors were introduced and the use of incandescent lamps continued to increase. By 1886, the DC systems were experiencing limitations because they could deliver energy only a short distance from their stations since their voltage could not be increased or decreased as necessary. In the United States, the use of alternating current (AC) was championed by George Westinghouse and Nikola Tesla. In 1885, a commercially practical transformer was developed, which allowed the development of an AC system. A 4000 volt AC transmission line was installed between Oregon City and Portland, 13 miles away. A 112 mile, 12,000 volt, three-phase line went into operation in 1891 in Germany. The first three-phase line in the United States (2300 volts and 7.5 miles) was installed in 1893 in California.3 In 1897, a 44,000-volt transmission line was built in Utah. In 1903, a 60,000-volt transmission line was energized in Mexico.4

In this early AC period, frequency had not been standardized. In 1891, the desirability of a standard frequency was recognized and 60 Hertz (Hz)5 was proposed. For many years 25, 50, and 60 Hz were standard frequencies in the United States. Much of the 25 Hz was used for railway electrification and has been retired over the years. The City of Los Angeles Department of Water and Power and the Southern California Edison Company both operated at 50 Hz, but converted to 60 Hz at the time that Hoover Dam power became available, with conversion completed in 1949. The Salt River Project was originally a 25 Hz system; most of it was converted to 60 Hz by the end of 1954 and the balance by the end of 1973.6

Over the first 90 years of its existence, until about 1970, electric consumption doubled about every ten years, a growth of about 7% per year. In the mid-1970s, due to increasing costs and serious national attention to energy conservation, the growth in the use of electricity dropped to almost zero. Today, growth is forecasted at about 1% per year until 2030.7

The growth in the utility industry has been related to technological improvements that have permitted larger generating units and larger transmission facilities to be built. In 1900, the largest turbine was rated at 1.5 MW. By 1930, the maximum size unit was 208 MW. This remained the largest size during the Depression and war years. By 1958, a unit as large as 335 MW was installed, and two years later in 1960, a unit of 450 MW was installed. In 1963, the maximum size unit was 650 MW and in 1965 the first 1000 MW unit was under construction. Unit sizes continued to grow, with generating units now as large as 1425 mW.8

Improved manufacturing techniques, better engineering, and improved materials allowed for an increase in transmission voltages in the United States to accompany the increases in generator size. The highest voltage operating in 1900 was 60 kV. In 1923, the first 220 kV facilities were installed. The industry started the construction of facilities at 345 kV in 1954, in 1964 500 kV was introduced, and 765 kV was put in operation in 1969 and remains as the highest transmission voltage in the United States.9 Larger generator systems required higher transmission voltage; higher transmission voltage made possible larger generators.

These technological improvements increased transmission and generation capacity at decreasing unit costs, accelerating the high degree of use of electricity in the United States. At the same time, the concentration of more capacity in single generating units, plants, and transmission lines had considerably increased the total investment required for such large projects, even though the cost per unit of electricity had come down.

Not all of the pioneering units at the next level of size and efficiency were successful. Sometimes, modifications had to be made after they were placed in operation; units had to be derated because the technology was not adequate to provide reliable service at the level intended. Each of these steps involved a risk of considerable magnitude to the utility, first to install a facility of a new type or a larger size or a higher transmission voltage. Creating new technologies required the investment of considerable capital that in some cases ended up being a penalty to the utility involved. To diversify these risks, companies began to jointly own power plants and transmission lines so that each company would have a smaller share and, thus, a smaller risk, in any one project. The sizes of generators and transmission voltage levels evolved together, as shown in Figure 1-1.10

A need for improved technology continues. New materials are being sought in order that new facilities can be more reliable and less costly. New technologies are required in order to minimize land use, water use, and the impact of the industry on the environment. The manufacturers of electrical equipment continue to expend considerable sums to improve the quality and cost of their products. Unfortunately, funding for such research by electric utilities through the Electric Power Research Institute (EPRI)11 continues to decline.

1.3 THE DEVELOPMENT OF THE NATIONAL ELECTRIC POWER GRID12

Electric power must be produced at the instant it is used. Needed supplies cannot be produced in advance and stored for future use. At an early date, those providing electric power recognized that peak use for one system often occurred at a different time from peak use in other systems. They also recognized that equipment failures occurred at different times in various systems. Analyses showed significant economic benefits from interconnecting systems to provide mutual assistance; the investment required for generating capacity could be reduced and reliability could be improved. This lead to the development of local, then regional, and, subsequently, three transmission grids that covered the United States and parts of Canada. In addition, differences in the costs of producing electricity in the individual companies and regions often resulted in one company or geographic area producing some of the electric power sold by another company in another area. In such cases, the savings from the delivery of this “economy energy” were usually split equally among the participants. Figure 1-2 shows the key stages of the evolution of this grid. Figure 1-3 shows the five synchronous power supply areas currently existing in North America.

Figure 1-1. Evolution of generator sizes and transmission voltages.

The development of these huge areas in each of which all generation is connected directly and indirectly by a network of transmission lines (the grid) that allows the generators to operate in synchronism presents some unique problems because of the special nature of electric power systems. Whatever any generator or transmission line in one area does or does not do affects all other generators and transmission lines in the same area, those nearby more significantly and those distant to a lesser degree. In the Eastern Grid (or Interconnection), the loss of a large generator in Chicago can affect generators in Florida, Louisiana, and North Dakota. Decisions on transmission additions can affect other systems many hundreds of miles away. This has required the extensive coordination in planning and operation between participants in the past. New procedures will be needed in the future.

Figure 1-2. Key stages in the evolution of the grid in the United States.

Figure 1-3. Synchronous power grids in North America.

As stated by Thomas P. Hughes of the University of Pennsylvania in the September 1986 issue of CIGRE Electra:13

Modern systems are of many kinds. There are social systems, institutional systems, technical systems, and systems that combine components from these plus many more… An example of such a technological system… is an electric power system consisting not only of power plants, transmission lines, and various loads, but also utility corporations, government agencies, and other institutions… [P]roblems cannot be neatly categorized as financial, technical, or managerial; instead they constitute a seamless web. . . . [E]ngineering or technical improvements also require financial assistance to fund these im-provement(s) and managerial competence to implement them.

1.4 “THE GOLDEN AGE”

The golden age of electric utilities was the period from 1945 to 1965. During this period, there was exponential load growth accompanied by continual cost reductions. New and larger plants were being installed at a continuously lower cost per kilowatt, reflecting economics of scale. Improvements in power plant efficiency were being obtained through higher temperatures and pressures for the steam cycle, which lowered the amount of fuel required to produce a kilowatt hour of electric energy. New generating plants were being located at the mine mouth, where coal was cheap, and power was transmitted to the load centers. This required new, higher voltage transmission lines since it had been found that transmitting electric energy, called “coal by wire,” was cheaper than the existing railroad rates.

The coordination between utilities was at a maximum. The leaders of the industry involved in planning the power systems saw the great advantage of interconnecting utilities to reduce capital investments and fuel costs. Regional and interregional planning organizations were established. The utilities began to see the advantage of sharing risk by having jointly owned units.

On the analytical side, improved tools were rapidly being developed. Greatly improved tools for technical analysis, such as computers, began to appear, first as analog computers and then as digital computers. At the same time, the first corporate financial models were developed for analyzing future plans for possible business arrangements for joint projects, of costs to the customers, for the need for additional financing, and the impact on future rates.

All of these steps reduced capital and fuel costs, which resulted in lower rates to customers. Everyone was happy. The customers were happy because the price of electricity was going down. Investors were happy because their returns on investments and the value of their stock were increasing. System engineers were happy because they were working on interesting and challenging problems that were producing recognized benefits, and their value to the utility organizations was increasing. Finally, business managers were happy that they were running organizations that were functioning smoothly and were selling their product to satisfied customers.

Blackouts and the Reliability Crisis

The first blow to this “golden age” was the blackout of New York City and most of the Northeast in 1965, which was caused by events taking place hundreds of miles away at Niagara Falls. The government’s reaction was immediate. Joseph C. Swidler was then Chairman of the Federal Power Commission. On order from President Johnson, he set up investigative teams to look into the prevention of future blackouts. As a result, they wrote an excellent report called Prevention of Power Failures, which is a classic to this day.14 This report and a number of subsequent blackouts lead to increasing attention by Congress and the Federal regulatory agen-cies—the Federal Power Commission (FPC), now called the Federal Energy Regulatory Commission (FERC),15 and the Department of Energy (DOE)16—to questions of reliability and increasing study. As an alternate to additional legislation, the industry recognized the need to govern itself and formed the National Reliability Council (NERC)17 and the Electric Power Research Institute (EPRI). Formal regional reliability criteria were developed, reliability conditions monitored, and major funds contributed to develop new technology.

Notwithstanding these criteria, the start of the twenty-first century was marked by the largest blackout the United States has ever experienced. Influenced by the blackout, Congress passed the Energy Policy Act of 2005 (EPAct05), including a provision that adherence to nationwide planning and operating standards be mandatory and providing for an expanded role for FERC in oversight of the planning and operation of the industry’s operation in the name of reliability.

The Environmental Crises—The Shift to Low-Sulfur Oil

Starting shortly after the reliability crisis, and overlapping it considerably, was the environmental crisis. Both the public and the government became concerned about air quality, water quality, and the effect of electricity production on the environment. New environmental legislation was passed. These concerns made the siting of new power plants very difficult. The power industry began installing nuclear units (which essentially have no exhaust), converting some of the existing coal-burning units to low-sulfur oil, providing electrostatic precipitators to filter out particu-late emissions, installing scrubbers to remove sulfur combustion products, and installing cooling towers so rivers would not heat up. All of these steps helped meet new government environmental requirements but significantly increased capital costs and fuel costs.18

The Fuel Crisis—The Shift from Oil

While these changes and additions were still underway, the industry was overtaken by another crisis. In 1973, the OPEC organization stopped all delivery of oil to the United States. This raised serious questions about plans to reduce air pollution by converting existing coal-burning units to oil. Plans were cancelled to convert generation to oil (at a considerable financial penalty). Huge increases in the price of fuel occurred.

The Financial Crisis

At the same time, the country found itself in an inflationary spiral; the cost of money rose to double-digits rates. All utility costs increased rapidly, requiring large rate increases. Because of the political impacts of such rate increases, many state regulatory commissions rejected these requests, thus exacerbating the financial problems of utilities. The depressed economy and rising costs of electricity dampened electric sales and load growth. The financial crisis resulted in a period of increasing costs, declining revenue, the lack of load growth, and large amounts of generating capacity under construction that would not be needed as soon as originally projected. Utilities were forced to cancel construction of projects already underway, resulting in large cancellation payments.

In 1979, a major accident occurred at the Three Mile Island Nuclear Plant in Pennsylvania. In response, the Nuclear Regulatory Commission issued orders greatly increasing the safety standards for nuclear power plants and requiring major design modifications. In combination with the high levels of inflation being experienced at the same time, massive overruns occurred in the cost of nuclear plants still under constructions. The service dates for many plants were delayed, in some cases for many years. These delays amplified the utilities’ financial crisis even further because there was an appreciable investment in these partially completed plants on which earnings were required, even though the plants were not operating and producing any electricity. Ten-fold cost increases were experienced by many of these plants. Some units that were built were never run. As a result of the cost issues and the greatly increased public concern over the safety of nuclear plants, proposals to construct new nuclear generation plants were brought to a standstill. There have been no new nuclear power plants built in the United States for many years, although the nuclear industry continued to flourish overseas. Recent Federal legislation seeks to rein-vigorate the nuclear option,19 primarily as an alternative to imported oil and as a noncarbon-emitting source of electricity, although the issue of nuclear waste disposal remains to be solved.20

The Legislative and Regulatory Crisis

At about the same time, the Federal Government had become very chaotic and unpredictable in the regulations it issued. Some believed that paying to reduce peak power consumption was more economical than building new generating and transmission capacity. This concept has been called least-cost, demand-side, or integrated resource planning.

The Public Utility Regulatory Policies Act (PURPA) legislation, passed in 1978, prescribed the use of “avoided costs” for determining payments to independently owned cogenerators and qualifying facilities (QFs), such as low-head hydro and garbage burners. These “avoided costs” were the alternate utility costs for producing electricity based on the alternates available to the utility system. They were based on estimates of future costs, made by state regulators, which turned out to be much higher than the actual costs that occurred, primarily because of the significant overestimates of the future price of fuel. Unfortunately, many utilities were required to sign long-term contracts for purchased energy reflecting these cost estimates. The avoided-cost approach led to excessive payments to some cogenerators and other qualifying facilities. Subsequently, some utilities had to make very large payments to the plant owners to cancel such contracts or to purchase the plants.

The next step by some state regulatory commissions was the proposal and, in some cases, the adoption, of competitive bidding procedures for new generators.

The Energy Policy Act of 1992 (EPAct92), FERC Orders 888 and 889, and various other FERC orders and notices followed, all seeking to foster a competitive wholesale market for electricity. One of the approaches implemented in some areas called for competitive bidding for the provision of the electricity needed each hour. It required all bidders whose proposals were accepted to be paid the highest bid accepted for the hour even though their proposal was lower. Proponents of the industry restructuring claim that restructuring has reduced costs to consumers. This claim is not accepted by all observers. Additionally, the rapid development of expanded wholesale markets with many new participants resulted in an increased level of complexity in operations, not always matched by the development and deployment of the necessary hardware, software and operational control necessary to maintain reliability. Rapidly rising costs, declining reliability, and developing procedures for manipulating electricity prices, have all increased concern and scrutiny of the electric power industry.

The Energy Policy Act of 2005 (EPAct05) and subsequent orders by FERC greatly increased the role of the federal government in the oversight of the planning and operation of the industry.

1.5 GLOBAL WARMING CRISIS AND CONCERNS ABOUT CARBON EMISSIONS

Scientists and environmentalists have been sounding a warning that the earth is becoming warmer and that the potential effects on the world’s population and ecosystems would be a disaster. Although recent data indicates that the earth has, on average, experienced a warming trend, the argument for the existence of long-term global warming is still contentious. Data on the earth’s temperature can be found at the National Oceanic and Atmospheric Administration (NOAA) National Climatic Data Center.21

Irrespective of the validity of either the position of the global warming proponents or those who argue against global warming, a groundswell of political/environmental opinion is seeking to determine if the activities of mankind have contributed to or are causing the temperature increase and what steps could be taken to mitigate or eliminate any such causes. Proposals to reduce greenhouse gas emissions, including those of the utility industry, are being considered by Congress as this book goes to press.22

1.6 RESTRUCTURING, COMPETITION, AND THE INDUSTRY OWNERSHIP STRUCTURE

At the turn of the twentieth century, the United States was dotted with approximately 5000 isolated electric plants, each servicing a small area. Entrepreneurs bought these systems to form larger systems. It was easier to raise cash and savings could be obtained by coordinating generation, transmission, and the distribution system development over a wider region.

In the 1920s and early 1930s, large utility holding companies were formed. Practices in the electric power industry that lead to additional economies of scale often lead to opportunities for major financial abuses. The concentration of economic power in fewer and fewer organizations, through highly leveraged purchases of companies, led to Congress passing the Public Utility Holding Company Act of 1935 (PUHCA).23

Table 1-1. Installed net summer generation capacity by producer type, Summer 2007

Source: EIA.

Producer typeNumber of generatorsNet summer capacity (mW)Electric utilities9,237571,200Independent power producers5,138357,278Subtotal14,375928,478Customer owned64637,254Commercial6352,312Industrial1,68626,844Subtotal2,96766,410Total all sectors17,342994,888

Over more than 100 years, the ownership of generation plants and transmission and distribution systems has evolved. For many years, generation was owned by investor-owned companies; rural electric cooperatives; various nonfederal governments, such as municipals, states, irrigation districts, and so on; and a number of Federal Authorities. Since the early 1990s, private ownership of generation has greatly increased. Table 1-124 shows the ownership of U.S. generating facilities. In 2007, independent power producers owned 35.9% of the capacity, up from 25.8% in 2000.

Transmission systems are still owned by the same entities as above although operational control has been ceded to independent third parties such as ISOs and RTOs. A few merchant transmission lines have been built and others are proposed.

1Homer M. Rustebakke, 1983, Electric Utility Systems and Practices, 4th ed., Wiley.

2Ibid.

3Ibid.

4Ibid.

5One hertz is equal to one cycle per second.

6Rustebakke, op. cit.

7Energy Information Agency (EIA), Annual Energy Outlook, 2009.

8The vast majority of the approximately 65 units larger than 1000 mW are nuclear units constructed in the 1970s and 1980s. Since then, the largest of the new capacity additions have been significantly smaller. For example, the Energy Information Agency’s list of new capacity for the period September 2007–August 2008 indicates the largest unit was 558 mW.

9Work on UHV (voltages 1000 kV or higher) is underway in China, India, and Brazil. The State Grid Corporation of China is working on a 1000 kV UHV transmission project connecting North and Central China.

10J. A. Casazza, 1993, The Development of Electric Power Transmission—The Role Played by Technology, Institutions, and People, IEEE Case Histories of Achievement in Science and Technology, Institute of Electrical and Electronic Engineers.

11See Chapter 19 for a discussion of EPRI, the industry’s research organization.

12Casazza, op. cit.

13J. A. Casazza, 1993, The Development of Electric Power Transmission—The Role Played by Technology, Institutions, and People, IEEE Case Histories of Achievement in Science and Technology, Institute of Electrical and Electronic Engineers.

14Federal Power Commission, Prevention of Power Failures, Volume I, Report to the Commission, Washington, D.C., July 1967.

15FERC, The Federal Energy Regulatory Commission, is the successor to the Federal Power Commission (FPC). See Chapter 14 for a discussion of FERC.

16 After its formation in 1977. See Chapter 14 for a discussion of the DOE.

17See Chapter 10 for a discussion of NERC.

18In the early 2000s, concerns about perceived global warming and the effect of carbon-based fuels are driving measures to reduce carbon emissions.

19See discussion in Chapter 6 of new nuclear technologies.

20”President Obama’s proposed budget all but kills the Yucca Mountain project, the controversial Nevada site where the U.S. nuclear industry’s spent fuel rods were to spend eternity. There are no other plans in the works, so for now the waste will remain next to Zion and 103 other reactors scattered across the country.” See Los Angeles Times, March 11, 2009 article by Michael Hawthorne.

21http://www.ncdc.noaa.gov/oa/climate/globalwarming.xhtml#q3.

22 See Chapter 5 for a discussion of this issue.

23PUHCA was repealed by the Energy Policy Act of 2005, discussed in Chapter 13.

24In the first edition of this text, additional information was provided in more detail on ownership interests. Unfortunately, the Energy Information Agency no longer publishes reports with the additional detail.

CHAPTER 2

THE ELECTRIC POWER SYSTEM

This chapter gives an overview of the electric power system. The electric power industry delivers electric energy to its customers that they, in turn, use for a variety of purposes. Although power and energy are related,25 customers usually pay for the energy they receive, not for the power.

An electric power system is comprised of the following parts:

The customers26 who require the electric energy and the devices in which they use the electric energy: appliances, lights, motors, computers, industrial processes, and so onThe sources of the electric energy: electric power plants and electric generation systems of various types and sizesThe delivery system by which the electric energy is moved from the generators to the customers

Taken together, all of the parts that are electrically connected or intertied operate in an electric balance. The technical term used to describe the balance is that the generators operate in synchronism with one another. Later, we will discuss how this concept of being in synchronism applies in the United States and Canada.

2.1 THE CUSTOMERS

Customer usage is typically referred to as customer demand, customer load, or “the load.” The peak usage, usually measured over an hour, a half hour, or 15 minutes (peak demand) is measured in either kilowatts or megawatts. The energy used by a typical residential or small commercial customer is measured in kilowatt-hours and that used by larger customers in megawatt-hours.

Industry practice has been to group customers by common usage patterns. Typically, these customer classes (or groups) are:

Residential customersCommercial customersIndustrial customersGovernmental customersTraction/railroad customers

A reason for delineating customer types is to recognize the costs that each customer class causes in the provision of electric service since different customer classes have different usage patterns with differing impacts on the capital and operating costs. In a regulated environment, in which customers are charged for their usage of electricity based on the cost of that supply, these classifications allow different menus of charges (rates) to be developed for each customer class.

In order to establish schedules of charges (rates) for each class of customer, utilities perform studies of the contributions of the various classes to the utility’s costs. These are called cost-of-ser-vice studies.

Analyzing different customer types also facilitates forecasting changes in customer’s electric requirements. These forecasts are required for long-range planning and short-range operating purposes.27

Individual customer requirements vary by customer type and by hour during the day, by day during the week, and by season. For example, a residential customer’s peak hour electricity consumption will normally occur in the evening during a hot summer day when the customer is using both air conditioning, lighting, and perhaps a TV, computer, or other appliances. A commercial customer’s peak hour consumption might also occur during the same day but during afternoon hours when workers are in their offices.

The time of day when a system, company, or geographic area peak occurs depends on the residential, commercial, and industrial customer mix in the area. The aggregate customer annual peak demand usually occurs during a hot summer day or a cold winter day, depending on the geographic location of the region and the degree of customer use of either air conditioning or electric heating. The electric system is built to meet the maximum aggregate system and local area peak customer demand for each season.

Diversity refers to differences in the time when peak load occurs. For example, if one company’s area is heavily commercial and another’s is heavily residential, their peaks may occur at different times during the day or even in different seasons. This timing difference gives the supplying company the ability to achieve savings by reducing the total amount of capacity required.

The types of electric devices customers use also have an important bearing on the performance of the electric system during times of normal operation and times when electrical disturbances occur, such as lightning strikes, the malfunctioning and loss of generating resources, or damage to parts of the delivery system. Some types of customer equipment, such as large motors, can require that devices be installed to provide extra support to maintain the power system’s voltage.

The electric system has metering equipment to measure and record individual customer electric usage (except for street lighting) and systems to bill and collect appropriate revenues. For most customers, the meters measure an aggregate energy usage. For larger customers (usually commercial and industrial), meters also are used that record peak demand.

2.2 SOURCES OF THE ELECTRIC ENERGY—GENERATION

There are a number of ways to produce electricity, the most common commercial way being the use of a synchronous generator driven by a rotating turbine. The combination is called a turbine– generator.

The most common types of turbine–generators are those in which a fossil fuel is burned in a boiler to produce heat to convert water to steam, which drives a turbine. The turbine is attached (coupled) to the rotating shaft (armature or rotor) of a synchronous generator in which the rotational energy is transformed to electrical energy. In addition to the use of fossil fuels to produce the heat required to change the water to steam, there are turbine–generators that rely on the fission of nuclear fuel to produce the heat. Other types of synchronous generators are those in which the turbines are driven by moving water (hydro turbines) and gas turbines that are turned by the exhaust of a fuel burned in chamber containing compressed air.

For each type of system, there are many variations incorporated in the power plant in order to improve the efficiency of the process. Hybrid systems are also in use; an example is a combined-cycle generator in which the exhaust heat from a gas turbine is used to help provide heat for a steam-driven turbine. Typically, more than one of these generating facilities are built at the same site to take advantage of common infrastructure facilities such as fuel delivery systems, water sources, and convenient points to connect to the delivery system.

A small but not insignificant segment of the electric generation in the country includes technologies that are considered more environmentally benign than traditional sources, such as geothermal, wind, solar, and biomass. In many of these technologies, DC power is produced and use is made of inverters to change the DC to the alternating current needed for transmission and use.

Table 2-1 shows that in 2007 there were 994,888 mWs of capacity installed in the United States. Natural gas (39.5%), coal (31.4%), and nuclear (10.1%) comprised the largest sources of the energy for the production of electricity. A different picture is presented in Table 2-2. This table shows that the actual production of electricity relied most heavily on coal (48.5%), with natural gas (21.6%) and nuclear (19.4%) producing similar amounts.

Since the first edition of this book (2003), the vast majority of new capacity has used natural gas as its fuel. Continuing this trend, natural-gas-fired generators are planned as the largest source of new capacity, as shown in Table 2-3. There are significant changes from the forecast in the earlier text. In that text, there was no new coal or nuclear generation planned. The other major change is the inclusion of a significant amounts of wind power in the present forecast.

Table 2-1. Installed summer capacity by energy source, Summer 2007

∗Source: January 21, 2009 EIA Report “Electric Power Annual 2007.”

Energy sourceGenerator net summer capacity, MWsCoal312,738Petroleum56,068Natural gas392,876Other gases2,313Nuclear100, 266Hydroelectric conventional77,885Other renewables∗30,069Pumped storage21,886Other788Total994,888

Generators are selected, sized, and built to supply different parts of the daily customer load cycle. One type of generator might be designed to operate continuously at a fixed level for the entire day. This is a base-loaded generator. Another generator might be designed to run for a short period at times of peak customer demand. This is a peaking generator. Others might be designed for intermittent service.

Table 2-2. Fuel sources used to produce electricity, 2007

*Source: January 21, 2009 EIA Report “Electric Power Annual 2007.”

Energy sourceCoal48.5%Petroleum1.6%Natural gas21.6%Other gases0.4%Nuclear19.4%Hydroelectric6.0%Other renewables∗2.5%Other0.3%Total100%

Table 2-3. Planned nameplate capacity additions from new generators, by energy source, 2008 through 2012

∗Source: January 21, 2009 EIA Report “Electric Power Annual 2007.”

Energy sourceNameplate capacity (mWs)Coal23,347Petroleum1,910Natural gas48,100Other gases0Nuclear1,270Hydroelectric conventional236Wind14,617Solar thermal and photovoltaic2,395Other renewables1,098Pumped storage0Other22Total92,996

One important aspect of the selection of a particular generator is the trade-off between its installed cost and its operating costs. Base-loaded generators have much higher installed costs per unit of capacity than peaking generators but much better efficiency and lower operating costs. Included in this decision is the availability and projected cost of fuel.

Prior utility practice has been to have enough generation available to meet the forecast customer seasonal peak demand plus an adequate reserve margin. Reserve margins were determined by conducting probability studies considering, among other things, the reliability of the existing generation and potential future loads. Systems that were mainly hydro-generation-based had lower reserve margins (∼12%) than systems that had nuclear-, coal-, or oil-fired generation (∼16–24%). The availability of aid from neighboring systems during shortages also had a large impact on the required reserve.

2.3 THE DELIVERY SYSTEM

A system of overhead wires, underground cables and submarine cables is used to deliver the electric energy from the generation sources to the customers. This delivery system, which electrically operates as a three-phase, alternating current system, has two major parts: transmission and distribution. Transmission is the facilities that deliver electricity from generators to substations which supply distribution facilities. Distribution facilities deliver the electricity to customers.

TransmissionSubtransmissionPrimary distributionSecondary distribution

The wires that make up the three phases are collectively called a line, circuit, or, when referring to the distribution system, a feeder.

The characteristic that differentiates the four parts of the delivery system from one another is the voltage at which they operate. In any one region of the country, transmission operates at the highest voltages, subtransmission at a lower voltage, then the primary distribution followed by the secondary distribution.

There is no uniformly agreed upon definition of what voltages constitute the transmission system. Some organizations consider voltage levels of 230 kV and above, whereas others consider voltage levels of 115 kV and above.28Table 2-4 shows the voltages that generally are considered for each grouping in the United States.

The transmission systems in the various parts of the United States have different characteristics because of differences in the locations of generating units and stations in relation to the load centers, differences in the sizes and types of generating units, differences in geography and environmental conditions, and differences in the time that the transmission systems were built. Due to these differences, we find different transmission voltages in various sections of the country; in some areas there is 765 kV, in others 500 kV and in others 345 kV.

As the industry developed, generation sites were usually located away from high-density customer load centers and the high-voltage transmission system was the most economic and reliable way to move the electricity over long distances. When new, large central station generating plants were built, they either were connected to the nearest point on the existing transmission system or they were the trigger to institute the construction of transmission lines at a new higher transmission voltage.29 The connection points are called substations or switching stations. These new higher voltage lines were connected to the existing system by means of transformers. This process is sometimes referred to as an overlay and resulted in older generation being connected to transmission at one voltage level and newer, larger generation connected at a new, higher voltage level. Over time, in some areas of the country, the lower voltage transmission facilities were called sub-transmission systems.

Table 2-4. Common HVAC transmission voltages in the United States

In addition to the listed voltages, there are a number of high-voltage, direct current (HVDC) installations that are classified as transmission.

SystemVoltages includedTransmission∗765 kV, 500 kV, 345 kV, 230 kV, 169 kV, 138 kV,115 kVSubtransmission169 kV, 138 kV, 115 kV, 69 kV, 34.5 kV, 27 kVPrimary distribution33 kV, 27 kV, 13.8 kV, 4 kVSecondary distribution120/240 volts, 120/208 volts, 277/480 volts∗

The increase of transmission voltage levels in the United States in the twentieth century was shown in Figure 1-1. In 1999, there were almost 154,500 miles of HVAC transmission lines operating at a voltage of 230 kV or higher in the United States. This total had grown to over 200, 000 miles in 2007.

Transformers enable the wires and cables of different voltages to operate as a single system. A transformer is used to connect two (or more) voltage levels.30

Transformers are installed at the generating plant to allow the generators, whose terminal voltage is typically between 13 kV to 24 kV, to be connected to transmission. These are called generator step-up transformers. As the delivery system brings the electricity closer to the customers, transformers connect the higher voltage system to lower voltage facilities. Connections can be made to the local subtransmission system or directly to the primary distribution system. These are step-down transformers. Figure 2-1 shows a conceptual sketch of a power system.

Figure 2-1. Conceptual diagram of a power system.

The connection point between the transmission system or the subtransmission system and the primary distribution system is called a distribution substation.31 Depending on the size of the load supplied, there can be one or more transmission or subtransmission lines supplying the distribution substation. A distribution substation supplies a number of primary distribution feeders. These distribution feeders can supply larger customers directly or they connect to a secondary distribution system through a transformer affixed to the top of a local utility pole or in a small underground installation.