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89–419PS 2004

KEEPING THE LIGHTS ON:

REMOVING BARRIERS TO TECHNOLOGY

TO PREVENT BLACKOUTS

HEARING

BEFORE THE

SUBCOMMITTEE ON ENERGY

COMMITTEE ON SCIENCE

HOUSE OF REPRESENTATIVES

ONE HUNDRED EIGHTH CONGRESS

FIRST SESSION

SEPTEMBER 25, 2003

Serial No. 108–23

Printed for the use of the Committee on Science

(

Available via the World Wide Web: http://www.house.gov/science

(II)

COMMITTEE ON SCIENCE

HON. SHERWOOD L. BOEHLERT, New York, Chairman

LAMAR S. SMITH, Texas

CURT WELDON, Pennsylvania

DANA ROHRABACHER, California

JOE BARTON, Texas

KEN CALVERT, California

NICK SMITH, Michigan

ROSCOE G. BARTLETT, Maryland

VERNON J. EHLERS, Michigan

GIL GUTKNECHT, Minnesota

GEORGE R. NETHERCUTT, JR.,

Washington

FRANK D. LUCAS, Oklahoma

JUDY BIGGERT, Illinois

WAYNE T. GILCHREST, Maryland

W. TODD AKIN, Missouri

TIMOTHY V. JOHNSON, Illinois

MELISSA A. HART, Pennsylvania

JOHN SULLIVAN, Oklahoma

J. RANDY FORBES, Virginia

PHIL GINGREY, Georgia

ROB BISHOP, Utah

MICHAEL C. BURGESS, Texas

JO BONNER, Alabama

TOM FEENEY, Florida

RANDY NEUGEBAUER, Texas

RALPH M. HALL, Texas

BART GORDON, Tennessee

JERRY F. COSTELLO, Illinois

EDDIE BERNICE JOHNSON, Texas

LYNN C. WOOLSEY, California

NICK LAMPSON, Texas

JOHN B. LARSON, Connecticut

MARK UDALL, Colorado

DAVID WU, Oregon

MICHAEL M. HONDA, California

CHRIS BELL, Texas

BRAD MILLER, North Carolina

LINCOLN DAVIS, Tennessee

SHEILA JACKSON LEE, Texas

ZOE LOFGREN, California

BRAD SHERMAN, California

BRIAN BAIRD, Washington

DENNIS MOORE, Kansas

ANTHONY D. WEINER, New York

JIM MATHESON, Utah

DENNIS A. CARDOZA, California

VACANCY

SUBCOMMITTEE ON ENERGY

JUDY BIGGERT, Illinois, Chair

CURT WELDON, Pennsylvania

ROSCOE G. BARTLETT, Maryland

VERNON J. EHLERS, Michigan

GEORGE R. NETHERCUTT, JR.,

Washington

W. TODD AKIN, Missouri

MELISSA A. HART, Pennsylvania

PHIL GINGREY, Georgia

JO BONNER, Alabama

SHERWOOD L. BOEHLERT, New York

NICK LAMPSON, Texas

JERRY F. COSTELLO, Illinois

LYNN C. WOOLSEY, California

DAVID WU, Oregon

MICHAEL M. HONDA, California

BRAD MILLER, North Carolina

LINCOLN DAVIS, Tennessee

RALPH M. HALL, Texas

KEVIN CARROLL Subcommittee Staff Director

TINA M. KAARSBERG Republican Professional Staff Member

CHARLES COOKE Democratic Professional Staff Member

JENNIFER BARKER Staff Assistant

KATHRYN CLAY Chairwoman’s Designee

(III)

C O N T E N T S

September 25, 2003

Page

Witness List ............................................................................................................. 2

Hearing Charter ...................................................................................................... 3

Opening Statements

Statement by Representative Judy Biggert, Chairman, Subcommittee on Energy, Committee on Science, U.S. House of Representatives ........................... 8

Written Statement ............................................................................................ 9

Statement by Representative Nick Lampson, Minority Ranking Member, Subcommittee on Energy, Committee on Science, U.S. House of Representatives ....................................................................................................................... 10

Written Statement ............................................................................................ 11

Prepared Statement by Representative Jerry F. Costello, Member, Subcommittee on Energy, Committee on Science, U.S. House of Representatives ....................................................................................................................... 11

Witnesses:

Mr. James W. Glotfelty, Director, Office of Electric Transmission and Distribution, U.S. DOE

Oral Statement ................................................................................................. 12

Written Statement ............................................................................................ 14

Biography .......................................................................................................... 28

Mr. T.J. Glauthier, President and CEO, Electricity Innovation Institute, Palo

Alto, CA

Oral Statement ................................................................................................. 28

Written Statement ............................................................................................ 30

Biography .......................................................................................................... 36

Dr. Vernon L. Smith, Nobel Laureate, Professor at George Mason University

Oral Statement ................................................................................................. 37

Written Statement ............................................................................................ 40

Biography .......................................................................................................... 44

Mr. Thomas R. Casten, CEO, Private Power, LLC, Oak Brook, IL; Chairman,

World Alliance for Decentralized Energy

Oral Statement ................................................................................................. 45

Written Statement ............................................................................................ 48

Biography .......................................................................................................... 50

Discussion ................................................................................................................. 59

Appendix 1: Answers to Post-Hearing Questions

Mr. James W. Glotfelty, Director, Office of Electric Transmission and Distribution, U.S. DOE ............................................................................................. 78

Mr. T.J. Glauthier, President and CEO, Electricity Innovation Institute, Palo

Alto, CA ................................................................................................................. 80

Mr. Thomas R. Casten, CEO, Private Power, LLC, Oak Brook, IL; Chairman,

World Alliance for Decentralized Energy ........................................................... 86

Page

IV

Appendix 2: Additional Material for the Record

Assessment Methods and Operating Tools for Grid Reliability, An Executive

Report on the Transmission Program of EPRI’s Power Delivery Reliability

Initiative, February 2001, EPRI ......................................................................... 90

(1)

KEEPING THE LIGHTS ON: REMOVING BARRIERS TO TECHNOLOGY TO PREVENT

BLACKOUTS

THURSDAY, SEPTEMBER 25, 2003

HOUSE OF REPRESENTATIVES, SUBCOMMITTEE ON ENERGY, COMMITTEE ON SCIENCE, Washington, DC.

The Subcommittee met, pursuant to call, at 10:06 a.m., in Room

2318 of the Rayburn House Office Building, Hon. Judy Biggert

[Chairwoman of the Subcommittee] presiding.

2

3

HEARING CHARTER

SUBCOMMITTEE ON ENERGY

COMMITTEE ON SCIENCE

U.S. HOUSE OF REPRESENTATIVES

Keeping the Lights On:

Removing Barriers to Technology

to Prevent Blackouts

THURSDAY, SEPTEMBER 25, 2003

10:00 A.M.–12:00 P.M.

2318 RAYBURN HOUSE OFFICE BUILDING

1. Purpose

On Thursday, September 25, 2003 at 10:00 a.m., the Energy Subcommittee of the

House Committee on Science will hold a hearing to examine the role of technology

in preventing future blackouts and the current economic, regulatory and technical

barriers to improved reliability. The hearing will also examine the role of the Department of Energy’s (DOE) newly established Office of Electric Transmission and

Distribution in enhancing the power grid’s performance and reliability.

2. Witnesses

The following witnesses will testify at the hearing:

Mr. James W. Glotfelty is the Director of the U.S. Department of Energy’s Office

of Electric Transmission and Distribution. Previously, Mr. Glotfelty served as a senior advisor to the Secretary of Energy, where he was a co-leader in the Department’s

contribution to the National Energy Plan. Mr. Glotfelty also served as an advisor

on electricity to then-Governor Bush.

Mr. T.J. Glauthier is the President and Chief Executive Officer of the Electricity

Innovation Institute, a new non-profit affiliate of the utility industry’s research consortium (Electric Power Research Institute or EPRI). Prior to joining the Institute,

Mr. Glauthier was the Deputy Secretary and Chief Operating Officer of the Department of Energy and he served for five years at the Office of Management and Budget as the Associate Director for Natural Resources, Energy and Science.

Mr. Thomas R. Casten is the founding Chairman and CEO of Private Power LLC,

an independent power company in Oak Brook, IL, which focuses on developing

power plants that utilize waste heat and waste fuel. Mr. Casten also serves on the

board of the American Council for an Energy-Efficient Economy (ACEEE), the board

of the Center for Inquiry, and the Fuel Cell Energy Board. He is also the Chairman

of the World Alliance for Decentralized Energy (WADE), an alliance of national and

regional combined heat and power associations, wind, photovoltaic and biomass organizations and various foundations and government agencies seeking to mitigate

climate change by increasing the fossil efficiency of heat and power generation.

Prior to Private Power LLC, Mr. Casten served as President of the International

District Energy Association and he received the Norman R. Taylor Award for distinguished achievement and contributions to the industry.

Dr. Vernon L. Smith is a Professor of Economics and Law and the Director of the

Interdisciplinary Center for Economic Science at George Mason University. Dr.

Smith, who won the Nobel Prize in economics in 2002, is widely recognized as the

‘father of experimental economics’ and his current research focuses on the design

and testing of markets for electric power, water, spectrum licenses and public goods

as well as continuing behavioral and evolutionary research on trust and reciprocity.

3. Overarching Questions

The hearing will focus on several overarching questions:

• Which technologies have the greatest potential to increase the reliability and

the efficiency of the U.S. electrical system both now and in the future? How

do the costs and benefits of these different technologies compare?

4

• What technologies are the DOE’s Office of Electric Transmission and Distribution developing? Do technologies to increase reliability exist and are they

ready to be deployed today?

• What is the state of R&D funding for our electrical systems? Where should

federal R&D funding be focused to ensure maximum benefit and future flexibility?

• What are the current and future barriers to the commercial application of

emerging technologies? What steps have been taken to address these obstacles?

4. Brief Overview

• On August 14, 2003, a major power outage occurred across the northeastern

and upper mid-western part of the United States and portions of Canada, affecting nearly 50 million customers.

• A joint U.S.-Canada task force has been established to determine the causes

of the blackout.

• A contributing factor of the recent blackout—and others—was the deregulation of the utility industry, where companies no longer own their own transmission lines. As a result, investment in the infrastructure has remained flat,

despite increases in electricity.

• Several solutions, including demand response, advanced transmission monitoring, communications and controls, advanced conductors, and distributed

generation, have been proposed, but barriers remain. New technologies are

not widely used, great variability in rules, regulations and technical specifications exist at the local level, and the cost to upgrade systems is high.

• Earlier this year (prior to the August blackout), the Administration established a new Office of Electric Transmission and Distribution at the Department of Energy in order to better address electric reliability concerns.

5. Background

On Thursday, August 14, a little after four o’clock in the afternoon, the power

went out for 50 million Americans. While the precise sequence of events is not yet

known, overloading of a portion of the Nation’s transmission system clearly played

an important role that was possibly compounded by human error and unclear lines

of responsibility. Although this was the largest blackout ever in the U.S., several

other serious blackouts have occurred in recent years, most notably in the Northwest in 1996, but also in San Francisco, Texas, New York State and Memphis, Tennessee.

To investigate the causes of the blackout, Energy Secretary Spencer Abraham is

co-chairing a U.S.-Canadian task force, and Mr. James Glotfelty, Director of DOE’s

Office of Electric Transmission and Distribution, is coordinating DOE’s participation

in the task force’s activities. One contributing factor in the most recent blackout and

several of the others was the changing structure of the utility industry. As a result

of deregulation, companies that generate electricity often no longer own the transmission lines they use for distribution. In addition, the companies that distribute

5

the electricity buy power from a variety of generators, meaning that transmission

lines move power in more directions than was originally contemplated. Worse, uncertainty over the future of deregulation has held investment in transmission lines

relatively flat as potential investors have been unsure of how they would reap a

profit. As a result, few additional transmission lines have been built and few have

been upgraded relative to the increase in demand.

Technology Solutions

Building new transmission lines would ease pressure on the system, but other options may be less expensive and create less controversy. Several of the options are

discussed below.

1) Demand Response

The demand for electricity varies widely over the course of a day, a month, and

even a season. Highest usage, or so-called ‘‘peak load,’’ typically occurs in the afternoons on hot summer days when air conditioners are on full power. This peak load

fills the transmission grid and strains the electrical system. It is therefore no surprise that blackouts often occur during these peak times of demand.

At times of peak demand, utilities bring on-line older and more inefficient electric

generators for the sole purpose of generating peak power. This, combined with the

fact that lines are hot from overloading electricity, results in higher costs and less

efficiency. Despite these increased costs—as much as ten times more—the price to

the average consumer does not change throughout the day, so the customer has no

incentive to change their demand.

Fortunately, new technologies coupled with pricing systems that charge more during peak periods can lead to significant reductions in demand. With so-called ‘‘demand response technologies,’’ a utility can send a signal to a home or business when

prices are peaking, and electrical equipment in the house can be programmed to

shut off specific appliances at a particular price level. For example, one program in

Florida is saving consumers an average of 15 percent off their energy bills by providing time-variant pricing and demand response technologies, for a fee. In turn,

this has reduced the average household demand during peak periods by about 50

percent.

2) Advanced Transmission Monitoring, Communications and Controls

Advanced transmission control systems—sometimes called ‘‘smart grid’’ technologies—can increase the ability of utilities to control power flows on transmission

lines. This emerging technology could prevent blackouts by enabling utilities to better monitor power flows and to limit current in dangerous situations without shutting it off completely. It could also more quickly and automatically direct the flow

of current away from overloaded lines. (There is mounting evidence that during the

August blackout controllers had little or no idea of the extent of the grid problems.)

New technologies can also help utilities better model the grid so they can make informed decisions about how to handle problems.

3) Advanced Conductors

New technologies, including advanced wires made from ceramic composites and

superconductors, could enable utilities to carry more electricity on fewer wires. Although more expensive, composites now being tested can carry two to three times

the power on the same diameter as regular wires. Superconducting wires, which are

also just starting to be tested, must be cooled below ¥300°F, but they can carry far

more current with only negligible losses in power. Superconducting wires are likely

to be first used in generators and transformers where they can dramatically increase efficiency, and then in short, constrained segments in urban settings, where

they can be placed in existing conduits to significantly increase the flow of electricity. Other technology includes devices for electricity storage. Although currently

expensive, storage could help reduce peak loads by storing off-peak power for use

when demand is high.

4) Distributed Generation

Distributed generation—the use of multiple, small generators close to the users

of the electricity—can ease demand by providing electricity that does not have to

move over the transmission system. Distributed generation technologies include fuel

cells, micro-turbines, reciprocating and Stirling engines, photovoltaics (solar energy),

wind turbines, and a variety of other technologies. Distributed generation also offers

security benefits, especially reduced vulnerability to catastrophic damage, whether

from natural or man-made disasters.

6

Barriers

Despite a large federal investment—DOE has funded more than $1.2 billion in research and development since 1980 for electricity transmission and distribution research, and at least as much for various distributed generation technologies—these

technologies are not in widespread use. Significant regulatory barriers, particularly

in the areas of interconnection standards and market structure, impede the adoption of new technology. Interconnection standards—rules, regulations, and technical

specifications that determine how electrical devices connect with local distribution

grids—vary widely among different localities. The lack of uniform national standards and the existence of sometimes arcane local rules and regulations often make

it prohibitively expensive to connect a distributed generation power unit to a distribution grid. A national consensus interconnection standard would reduce the cost

of hardware, and significantly reduce the need for installation inspections and onsite certifications. Market structures currently in place also vary significantly by region, but very few of them are designed to convey accurate price signals to consumers indicating the true costs of electricity usage at times of peak demand.

As is often the case, the cost of installing upgraded technology can be a barrier. Some have estimated that transmission grid modernization could cost $50 billion or

more over the next ten years. This translates to about one- or two-tenths of a cent

per kilowatt-hour (a dollar or two per month for the average customer). But the

costs of an unreliable electric system are even higher, with costs from the August

blackout alone estimated to be between $4 and $6 billion. As many local victims of

hurricane Isabel’s wrath will attest, extended blackouts can result in spoiled food,

lost work and other economic costs.

Office of Electric Transmission and Distribution

Secretary Abraham created the DOE Office of Electric Transmission and Distribution (OETD) earlier this year to address two primary functions: research and development (R&D) on electricity transmission and distribution technologies, and systems operation research and policy analysis related to the electric system. The programs run by the Office are not new; they come from various parts of DOE, primarily from the Office of Energy Efficiency and Renewable Energy (EERE).

The Department created the new office in response to recommendations from a

series of reports. The National Energy Policy, released in 2001, which directed the

Secretary to ‘‘examine the benefits of establishing a national grid, identify transmission bottlenecks, and identify measures to remove transmission bottlenecks.’’

The Department then commissioned The National Transmission Grid Study, which

was released in May 2002, which warned of the increasing likelihood of significant

blackouts. The Grid Study provided several recommendations to improve the operation of the system, including the elimination of transmission bottlenecks and the

creation of a new electricity office within DOE. Private sector groups such as the

Electric Power Research Institute (EPRI) have also recommended a significant investment in the power system. Its recent study, The Electricity Framework for the

Future, recommend increased federal investment in advanced electrical generation,

transmission and distribution technologies such as those discussed earlier in this

charter.

OETD’s fiscal year 2003 R&D budget of $80 million includes research on high

temperature superconductivity technologies, transmission systems, distribution and

electricity storage technologies conducted through contracts and cost-shared agreements with universities, national laboratories, and industry. The operations and

analysis subprogram includes policy modeling, analysis and technical assistance.

6. Questions for the Witnesses:

The witnesses were asked to address the following questions in their testimony

before the Subcommittee:

Questions for Mr. Glotfelty

• Briefly describe the responsibilities and reporting structure of the Office of

Transmission and Distribution.

• Briefly describe and rank the key vulnerabilities of the electrical grid as it

is built and managed today. Are there technological solutions that could contribute to the reduction of these key vulnerabilities?

• What barriers currently prevent wider adoption of these commercially available technologies? What policy choices would be most conducive to greater

adoption of these technologies?

• What was DOE’s decision process in identifying the technologies it is supporting/has supported through the Office of Electricity and Distribution?

7

Questions for Mr. Glauthier

• What technologies are commercially available or under development to improve the efficiency and reliability of our electrical system? Which technologies would you suggest receive the highest priority for targeted DOE research and development funding?

• What barriers currently prevent wider adoption of these commercially available technologies? What policy choices would be most conducive to greater

adoption of these technologies?

• What is the current level of investment by the private sector in improvements

to the grid that enhance its reliability? How can the private sector and the

Federal Government best share responsibility for ensuring the reliability of

the Nation’s electrical grid?

• What level of federal funding would be necessary and appropriate for research, development, demonstration and deployment of smart grid technology? What should the private share be?

Questions for Dr. Smith

• Briefly describe the market structure for the electricity sector as it existed 15

years ago and contrast it with the structure today.

• What barriers currently prevent wider adoption of commercially available energy technologies? What policy choices would be most conducive to greater

adoption of these technologies?

• How is uncertainty affecting the economics of investment in the electricity

sector? How can we structure a market to ensure reliable electricity at the

lowest cost?

• What are the incentives for utilities to invest in transmission research and

development? How can we encourage investment in research and development

in a highly competitive electricity sector?

Questions for Mr. Casten

• Please give a brief description of your current business ventures designed to

capture waste heat.

• How can distributed generation improve the reliability of the overall electrical

system? What other benefits does distributed generation provide?

• What barriers currently prevent wider adoption of commercially available energy technologies? What policy choices would be most conducive to greater

adoption of these technologies?

• Do some states or regions of the country do a better job at encouraging the

dissemination of distributed generation technologies? What specifically makes

them different?

8

Chairwoman BIGGERT. The hearing will come to order.

I want to welcome everyone to this hearing of the Energy Subcommittee. Our purpose here is to identify current and emerging

technologies and the barriers to their deployment that will help improve the reliability of our nation’s increasingly complex electrical

system.

The blackout that occurred on August 14 leaving 50 million

Americans without power was a startling reminder of the vulnerability of our current antiquated system and the enormous costs associated with such an unreliable system. Many communities in my

District, thankful that the blackout stopped short of Chicago,

watched and learned that the blackout meant so much more than

no electricity. They came to realize that a blackout could mean no

public transportation, no stoplights, no security lights, no heat or

air conditioning, and in some cases, no water.

While a national joint task force is still investigating the exact

causes of the August 14 blackout, it is clear that overloading of a

portion of the Nation’s transmission system played an important

role. But regardless of what the exact cause of the blackout was,

the bottom line is this: we simply can not meet today’s energy

needs with yesterday’s energy infrastructure. No pun intended, but

we are virtually in the dark ages when it comes to energy infrastructure. This is especially true with respect to the electric grid.

But the answer isn’t necessarily more lines or even necessarily

new and better ones. We must consider other, better ways to obviate the need for more lines, such as greater use of distributed generation and reducing peak demand for electricity through technologies that improve efficiency, communications, and controls. And

we must make better use of whatever lines we do have, which is

where advanced technology could have the greatest impact. Improved monitors of controls could prevent and isolate transmission

failures and other new technologies promised to enable the transmission system to sustain far greater loads.

Americans want affordable and reliable energy, and yet, because

we have ignored technology, we act as though the two are mutually

exclusive. The only way to have both at the same time is first to

take our head out of the sand and second by putting technology to

work and cutting some of the 1930’s style government red tape that

has stifled the development of new technology and infrastructure.

Our witnesses today will discuss currently available emerging

technologies and the regulatory and economic barriers that impede

their adoption. Their testimony also will provide an opportunity to

learn more about the Department of Energy’s newly formed Office

of Electric Transmission and Distribution and its work on these

issues.

As Congress works to eliminate barriers that discourage investment in new grid technologies and distributed generation, and consequently, as the competitive market begins to function properly,

this committee and this subcommittee, in particular, must do two

things: first we must ensure that whatever regulations remain do

not limit or impede technological solutions; and secondly, we must

ensure that the best and most promising technology is ready and

available for deployment. I hope our witnesses today can help shed

some light on how we can be successful on both fronts.

9

As the recent blackout demonstrated, the cost of continued inaction far exceeds the cost of action. Some estimate that the cost—

total cost of upgrading our electrical grid will be $50 billion or more

over the next 10 years, but the cost of an unreliable electric system

are even higher with costs of the August 14 blackout alone estimated to be between $4 billion and $6 billion. By investing in new

technologies to improve our electrical system, we are investing in

an infrastructure that supports virtually every component of our

economy. That is why a robust, resilient, and reliable electrical system is unquestionably in our nation’s interest. We must work together to determine the best way to get there. I think we can all

agree that advanced technologies can be a major part of the solution as long as the barriers to their deployment and use are removed.

I look forward to hearing today’s testimony and pursuing those

subjects in greater detail.

[The prepared statement of Mrs. Biggert follows:]

PREPARED STATEMENT OF CHAIRMAN JUDY BIGGERT

The hearing will come to order.

I want to welcome everyone to this hearing of the Energy Subcommittee. Our purpose here is to identify current and emerging technologies—and the barriers to their

deployment—that will help improve the reliability of our nation’s increasingly complex electrical system.

The blackout that occurred on August 14th, leaving 50 million Americans without

power, was a startling reminder of the vulnerability of our current, antiquated system, and the enormous costs associated with such an unreliable system. Many communities in my district, thankful that the blackout stopped short of Chicago,

watched and learned that the blackout meant so much more than no electricity.

They came to realize that a blackout could mean no public transportation, no stoplights, no security lights, no heat or air conditioning, and in some cases, no water.

While a bi-national task force is still investigating the exact causes of the August

14th blackout, it is clear that overloading of a portion of the Nation’s transmission

system played an important role. But regardless of what the exact cause of the

blackout was, the bottom line is this: we simply cannot meet today’s energy needs

with yesterday’s energy infrastructure. No pun intended, but we’re virtually in the

dark ages when it comes to energy infrastructure. This is especially true with respect to the electric grid.

But the answer isn’t just more lines, or even necessarily new and better lines. We

must consider other, better ways to obviate the need for more lines, such as greater

use of distributed generation, and reducing peak demand for electricity through

technologies that improve efficiency, communications, and controls.

And we must make better use of whatever lines we do have, which is where advanced technology could have the greatest impact. Improved monitors and controls

could prevent and isolate transmission failures, and other new technologies promise

to enable the transmission system to sustain far greater loads.

Americans want affordable and reliable energy, and yet, because we’ve ignored

technology, we act as though the two are mutually exclusive. The only way to have

both at the same time is: first, to take our head out of the sand; and second, by

putting technology to work and cutting some of the 1930’s-style government red tape

that has stifled the development of new technology and infrastructure.

Our witnesses today will discuss currently available and emerging technologies,

and the regulatory and economic barriers that impede their adoption. Their testimony also will provide an opportunity to learn more about the Department of Energy’s newly formed Office of Electric Transmission and Distribution, and its work on

these issues.

As Congress works to eliminate barriers that discourage investment in new grid

technologies and distributed generation, and consequently as the competitive market begins to function properly, this committee, and this subcommittee, in particular, must do two things. First, we must ensure that whatever regulations remain

do not limit or impede technological solutions. And secondly, we must ensure that

the best and most promising technology is ready and available for deployment. I

10

hope our witnesses today can help shed some light on how we can be successful on

both fronts.

As the recent blackout demonstrated, the cost of continued inaction far exceeds

the cost of action. Some estimate that the total cost of upgrading our electrical grid

will be $50 billion or more over the next ten years. But the costs of an unreliable

electric system are even higher, with costs of the August 14th blackout alone estimated to be between $4 and $6 billion. By investing in new technologies to improve

our electrical system, we are investing in an infrastructure that supports virtually

every component of our economy.

That’s why a robust, resilient, and reliable electrical system is unquestionably in

our national interest. We must work together to determine the best way to get

there. I think we can all agree that advanced technologies can be a major part of

the solution, as long as the barriers to their deployment and use are removed.

I look forward to listening to today’s testimony and pursuing these subjects in

greater detail.

Chairwoman BIGGERT. The Chair now recognizes the Ranking

Minority Member on the Energy Subcommittee for his only—his

opening statement.

Mr. LAMPSON. Thank you, Chairwoman Biggert. I want to thank

you for calling this very important hearing this morning. And certainly I want to thank our witnesses for joining us here today. We

appreciate having all of you.

The recent blackout suffered by 50 million Americans in the Midwest and the Northeast on August the 14th has indeed brought the

issue of electricity generation and transmission into clearer focus.

The blackout was the largest ever in the United States. And the

cost in the United States has been estimated to be somewhere between $4 billion and $6 billion.

This incident spurred the creation of a joint United States-Canadian task force on the factors that contributed to this event. As the

Administration, Congress, and the joint task force continue to examine the factors behind the incident, I believe that it’s imperative

that we consider the role technology can play in preventing future

blackouts. We need to ensure that our power transmission services

are reliable and secure while we continue to prevent future disruptions across the country. Technological advances will play a very

key role in this endeavor.

While I understand that many have called for the construction

of new transmission lines, I look forward to hearing from our witnesses about how smart grid and demand response technologies

might also help utility companies handle these problems in the future. Advanced conductors made from ceramic composites and

superconducting wires could also dramatically increase efficiency.

And I am also interested to hear about the role that reactive power

may have played in this incident and whether we have technological advances to help us understand this phenomenon.

My congressional district has the distinction of being serviced by

two electricity grids. My Houston-Galveston area constituents are

served by Electric Reliability Council of Texas, ERCOT, while my

Beaumont, Port Arthur, and Chambers County constituents are

under the Southeastern Electric Reliability Council, SERC. I have

reached out to the utility companies in my area for their thoughts

and their ideas on how we can improve the electricity grids. And

while it was the Midwest and Northeast on August the 14th, other

parts of the country have experienced blackouts in recent years,

and I am sure that other regions will also experience them in the

future.

11

So I am committed to working with our power companies, federal, State, and local officials to utilize available technologies and

to ensure that we minimize future disruptions. As a nation, we

must be proactive about these problems rather than reactive as we

respond to these challenges, and I look forward to hearing from our

witnesses.

Thank you, Madame Chairman.

[The prepared statement of Mr. Lampson follows:]

PREPARED STATEMENT OF REPRESENTATIVE NICK LAMPSON

I would like to thank Chairwoman Biggert for calling this very important hearing.

And I would also like to thank all of our witnesses for joining us here today.

The recent blackout suffered by 50 million Americans in the Midwest and Northeast on August 14th has brought the issue of electricity generation and transmission

into a clear focus.

The blackout was the largest ever in the United States and the cost to the U.S.

has been estimated at between $4 and $6 billion.

This incident spurred the creation of a joint United States-Canadian task force

on the factors that contributed to this event.

As the Administration, Congress and the joint task force continue to examine the

factors behind this incident, I believe it is imperative that we consider the role technology can play in preventing future blackouts.

We need to ensure that our power transmission services are reliable and secure

while we continue to prevent future disruptions across the country. Technological

advances will play a key role in this endeavor.

While I understand that many have called for the construction of new transmission lines, I look forward to hearing from our witnesses about how ‘‘smart grid’’

and ‘‘demand response’’ technologies might also help utility companies handle these

problems in the future.

Advanced conductors made from ceramic composites and superconducting wires

could also dramatically increase efficiency.

I am also interested to hear about the role that reactive power may have played

in this incident and whether we have technological advances to help us understand

this phenomenon.

My congressional district has the distinction of being serviced by two electricity

grids. My Houston and Galveston area constituents are served by the Electric Reliability Council of Texas (ERCOT), while my Beaumont, Port Arthur and Chambers

County constituents are under the Southeastern Electric Reliability Council (SERC).

I have reached out to the utility companies in my area for their thought and ideas

on how we can improve the electricity grids.

And while it was the Midwest and Northeast on August 14th, other parts of the

country have experienced blackouts in recent years and I am sure other regions will

also experience them in the future.

I am committed to working with power companies, federal, State and local officials to utilize available technologies and ensure that we minimize future disruptions.

As a nation we must be proactive about these problems rather than reactive as

we respond to these challenges.

Chairwoman BIGGERT. Thank you. I would like to ask at this

time for a unanimous consent that all Members who wish to do so

have their opening statements entered into the record. Without objection, so ordered.

[The prepared statement of Mr. Costello follows:]

PREPARED STATEMENT OF REPRESENTATIVE JERRY F. COSTELLO

Good morning. I want to thank our witnesses for appearing before this committee

to discuss removing barriers to technology to prevent blackouts. On August 14 and

15, 2003, the northeastern U.S. and southern Canada suffered the worst power

blackout in history. Areas affected extended from New York, Massachusetts, and

New Jersey west to Michigan, and from Ohio north to Toronto and Ottawa, Ontario.

Approximately 50 million customers were impacted, and the economic costs will be

staggering.

12

Getting to the bottom of things will not be easy, given the complexity of the electrical system, but will require answers to three simple questions. What exactly happened? Why did it happen? And how can it be prevented in the future? In answering

the last question, continued research and development in our electric system will

help us improve our grid system and hopefully prevent another blackout from occurring.

If future blackouts are to be avoided, we must fix these problems quickly and decisively and continue to promote research and development that will address the reliability and security of the electric energy transmission system. Southern Illinois

University (SIU) in my congressional district has been continuously working on research on a variety of electric transmission issues. SIU was among the first to receive research contracts from the Electric Power Research Institute (EPRI) in

launching the Flexible AC Transmission Initiative. In addition, SIU has received

grants from the National Science Foundation, the Department of Energy and Electric Utilities for electric transmission research. Further, the university is currently

working on Broad Band over Power Lines which is an emerging technology utilizing

the backbone of the power distribution network for the transmission of high-speed

data.

SIU is one example of promising work in improving our electric system; however,

more is needed. EPRI estimates that research and demonstration programs will require increased federal funding of approximately $1 billion, spread out over five

years, with the private sector contributing a significant amount of matching funding. I am interested in hearing from our witnesses about a public/private institutional role for research and development.

I welcome our panel of witnesses and look forward to their testimony.

Chairwoman BIGGERT. It is my pleasure to welcome our witnesses for today’s hearing and to introduce them to you. They are:

Mr. James Glotfelty, Director of the Office of Electric Transmission

and Distribution, U.S. Department of Energy; Mr. T.J. Glauthier,

President and CEO, Electricity Innovation Institute; Dr. Vernon

Smith, Nobel Laureate and Professor of Economics, George Mason

University; and Mr. Tom Casten, CEO, Private Power, LLC. I

would like to extend a special welcome to Mr. Casten, a constituent

of my District and to congratulate him on his impressive work he

has done for more than 25 years in developing and operating combined heat and power plants as a way to save money, increase efficiency, and lower emissions. Welcome to all of you.

As the witnesses know, spoken testimony will be limited to five

minutes each, after which Members will have five minutes each to

ask questions. So we will begin with Mr. Glotfelty.

STATEMENT OF MR. JAMES W. GLOTFELTY, DIRECTOR, OFFICE OF ELECTRIC TRANSMISSION AND DISTRIBUTION, U.S.

DOE

Mr. GLOTFELTY. Thank you very much.

Good morning, Chairman Biggert and Members of the Subcommittee. My name is Jimmy Glotfelty. I’m the Director of the

newly created Office of Electric Transmission and Distribution at

the Department of Energy. Thank you for the opportunity to testify

before you today on the role that technology can play in the development of a more robust and reliable electric system.

America’s electric system is facing serious problems: aging equipment, uncertain regulations at both the federal and State level, and

difficulty attracting investment capital, all in the face of rising demand. As you may know, the National Academy of Sciences called

America’s electric system ‘‘the supreme engineering achievement of

the 20th century.’’ However, as currently configured, there are serious questions about the ability of this system to satisfy the complex

needs necessary to power the economy in the 21st century.

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The U.S. Department of Energy is leading an effort to help facilitate the modernization of our nation’s aging electric grid. DOE, in

collaboration with industry and other partners, developed Grid

2030, a national vision for tomorrow’s electric system, and a road

map that outlines the key challenges for modernizing the grid and

suggested paths and—suggested paths to get there. The vision and

road map called for government and industry to work today in a

collaborative manner. They implement a five-part action agenda to

modernize the grid and achieve the Grid 2030 vision. This agenda

includes: study the feasibility of a national transmission backbone;

continue the development of critical technologies that make the future grid more stable, more efficient, and more reliable; accelerate

technology acceptance; strengthen market operations and allow the

marketplace to promote new technologies that strengthen our grid;

and finally, build multi-year public/private partnerships with industry, states, reliability councils to ensure that this vision becomes a reality.

Transmission, distribution, researching efforts at DOE have been

in existence for many years. Many commercialized technologies

that enhanced the reliability of the electric grid today began with

DOE research many years ago. However, there are many more

technologies that require further research, development, and demonstration to ensure their effective performance in the field. This

is critical to acceptance in the marketplace. For example, DOE is

working with industry to test high-capacity transmission lines

made of new materials that will carry more electrical current, reduce losses, and are lighter weight and lower in cost. Testing these

lines at our Oak Ridge National Lab Transmission Testing Center

will help industry reduce barriers that lead to commercial viability

of these products. New communication and control technologies are

necessary to promote an electricity grid with embedded intelligence

that will process vast amounts of information in less than a second

and help operators make more accurate reliability and economic decisions.

Advances in power electronics today already allow more power to

flow through existing systems. Improvements will better control

the flow of AC power flows and allow operators to isolate problems

that could cause larger regional disruptions. In the future, hightemperature superconductors have the potential to revolutionize

electric power delivery in America. The prospect of transmitting

large amounts of power through compact underground corridors

over long distances with minimal losses could significantly enhance

the overall efficiency and reliability of the electric system, all while

reducing fuel use and emissions. Superconducting technologies will

be used in generators, cables, transformers, storage devices, and

motors: equipment that crosscuts the entire electric power center.

While these technologies are still being developed, there are still

major stumbling blocks in their widespread deployment on the

grid. The primary reason is uncertainty: regulatory uncertainty

and financial uncertainty. The lack of investment in grid modernization has been caused by uncertainty in electric utility regulations at the federal and State level. The jurisdictional boundaries

are not clear, and the difficult transition from a tightly regulated

industry to one where competition and market forces play a greater

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role has taken years too long. Regulatory uncertainty has lasted almost a decade, and its consequences are beginning to be felt across

the Nation.

Investment uncertainty is directly tied to the state of regulation.

If markets see clear signals as to a return on investment, they will

invest. If not, the capital will flow to a more stable industry. During this time of uncertainty, both investment in the transmission

system and R&D funding by the industry has declined. In fact,

transmission reliability research at the Department of Energy was

zeroed out for three years in the 1990’s: ’96, ’97, and ’98. These private/public cutbacks have slowed the push for new technologies and

tools into the marketplace.

While this regulatory rethinking proceeds, several states have

implemented price caps as a way to protect consumers from price

shocks while the markets adjust to make policy—allow policy-makers to identify next steps. While attractive to the regulator, price

caps could very well hinder investment, because they raise the uncertainty of cost recovery for new equipment.

As you know, there are many things that must be done to bring

our electrical infrastructure up to a 21st century standard. August—the August 14 blackout is an example of what could happen

again in the future if we do not begin to focus on the improvement

of our grid today. The U.S. economy’s reliance on a secure, reliable

infrastructure has never been greater. Modernizing the grid will involve time, resources, and unprecedented levels of cooperation

among electric power industries, many and diverse stakeholders.

Neither government nor industry can shoulder these responsibilities alone. We must act now or risk greater problems in the future.

I thank you for the opportunity to testify before you today and

look forward to addressing your questions.

[The prepared statement of Mr. Glotfelty follows:]

PREPARED STATEMENT OF JAMES W. GLOTFELTY

Introduction

Chairman Biggert and Members of the Subcommittee, thank you for the opportunity to testify today on the role of new technologies in developing a more robust

electric system.

America’s electric system is facing serious problems: aging equipment and infrastructure, uncertain regulations and policies, difficulties attracting investment capital, and constrained supplies failing to meet rising demand. The National Academy

of Sciences called America’s electric system ‘‘. . .the supreme engineering achievement of the 20th century.’’ However, as currently configured, there are serious questions about the ability of this system to satisfy the increasingly complex electricity

needs of the 21st century.

The President is well aware of this problem. For example, on February 6th 2003,

President Bush reiterated the Administration’s policy to modernize the electric grid,

‘‘It is a plan to modernize our electricity delivery system. It is a plan which is needed now. It is needed for economic security. It is needed for national security.’’ The

August blackout highlighted the economy’s reliance on a secure and reliable electric

system. Billions of dollars in goods and services, in productivity and food, were lost.

Implementing the President’s plans for modernizing America’s electricity infrastructure is one of the U.S. Department of Energy’s top priorities. The President’s

National Energy Policy directed preparation of a detailed assessment of the major

bottlenecks in our nation’s transmission system, and in May 2002, Secretary Abraham issued The National Transmission Grid Study. This report made clear that

without dramatic improvements and upgrades over the next decade our nation’s

transmission system will fall short of the reliability standards our economy requires,

and will result in higher costs to consumers. The Department immediately began

taking steps to implement the improvements that are needed to ensure continued

15

growth and prosperity, working with Congress, States, and other stakeholders to

promote innovation and enable entrepreneurs to develop a more advanced and robust transmission system. The mission of DOE’s newly created Office of Electric

Transmission and Distribution is focused on achieving this end.

Opportunities for Modernizing America’s Electric System

Modernization includes the application of new and existing technologies to enhance the reliability and efficiency of the entire electric system. Electric reliability

and efficiency are affected by all four segments of the electricity value chain: generation, transmission, distribution, and end-use. Investing in only one area will not necessarily stimulate performance improvements across other segments of the integrated system. Increasing supply without improving transmission and distribution

infrastructure, for example, may actually lead to more serious reliability concerns.

Thus, to improve the reliability and efficiency of electric power in America—as

called for in the President’s energy plan—equipment upgrades as well as new technologies are needed throughout the electric system.

With electric generation, reliability is enhanced when additional supplies are

added to ensure that peak demands are met. Reliability is also enhanced when sufficient reserve capacity is available for scheduled and unscheduled maintenance, and

for emergency situations. Additional supplies can come from expansion of both central and distributed assets, representing a variety of technologies and fuel choices.

Efficiency is enhanced when more fuel-efficient generation technologies are used,

such as combined cycle combustion turbines and combined heat and power units.

However, expanding supplies without balancing investment in transmission and distribution infrastructure will place additional cost burdens on consumers, both in

terms of congestion and reliability. A reliable system requires balanced investment

in supply, delivery, and demand management.

With respect to electric transmission, reliability is enhanced when additional lines

are added to the grid, proper maintenance occurs in a timely manner, and when

grid operators are able to make adjustments, in real-time, to address fluctuations

in system conditions, particularly during periods of peak demand. Efficiency is enhanced when new transmission technologies are used that have reduced line losses,

and that have the capability to carry more current for a given size of conductor. The

Department is partnering today with industry to develop cost-effective transmission

solutions, including advanced composite conductors, high temperature superconductors, and wide area measurement systems.

With respect to electric distribution, reliability is enhanced when additional lines

are added, substation capabilities are expanded, proper maintenance occurs in a

timely manner, communications and interconnections systems facilitate distributed

energy development, and systems are protected better from natural disturbances.

Efficiency is enhanced when new distribution technologies are deployed that reduce

line losses, and information technologies optimize existing resources. The Department is working with States and industry to develop transformers, fault current

limiters, cables, and power electronics that will revolutionize the distribution system.

With respect to electric end-use, reliability is enhanced when demand response

programs manage electricity consumption in ways that result in lower overall peak

demand and a better balance between on- and off-peak usages. Actions can include

use of such technologies as real-time (or time-of-use) meters, and advanced energy

storage. Efficiency is enhanced when new appliances and equipment require less

electricity to produce equal (or greater) levels of service, such as advanced lighting,

heating, cooling, refrigeration, and motor drive devices. Although peak load management offers significant benefits to utilities, electric consumption is controlled by the

end-users. Their participation in a fully integrated energy system requires price

transparency.

Barriers to Electric Grid Modernization

For more than two decades, America has been under-investing in the modernization of the electric system. The primary reason is uncertainty: technical uncertainty;

regulatory uncertainty; and financial uncertainty. The consequences of this have

been significant: greater numbers of congested transmission corridors, a higher likelihood of brownouts and blackouts, and more economic losses from outages when

they do occur. Annual estimates of losses from outages and power quality disturbances range from $25 to $180 billion annually. Standard and Poor’s estimates the

economic losses from the August 14th blackout to be about $6 billion. Although

some estimate it will take $100 billion to modernize the electric system, this should

be compared against the scale of the existing electric industry: infrastructure worth

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approximately $800 billion (including generation), and revenues approaching $250

billion annually.

There are electricity technologies that are ready today to be used for grid modernization projects. However, electric assets are capital-intensive and long-lived, so

the stock turnover process is relatively slow. Much of the Nation’s electric infrastructure of power lines, substations, switchyards, and transformers has been in

service for 25 years, or longer.

The primary reason for the lack of investment in grid modernization is the financial uncertainty caused by the uneven process of restructuring of electric utility regulation, at both the federal and state levels. The electric power business currently

is in and has for the last few years been in the midst of a difficult transition from

a tightly regulated industry to one where competition and market forces play a

greater role.

This transition has been slow and there have been missteps. For example, the unfortunate experience in California cost citizens billions of dollars, and has caused

other states to re-think their approach to electric power regulation.

Regulatory uncertainty has affected other aspects of grid modernization. For example, there seems to have been a substantial decline in the level of spending recently by the electric power industry in research and development. The Electric

Power Research Institute reports that its R&D funding from member utilities has

fallen from about $600 million annually in 1994 to about $300 million annually in

2001. Federal spending on electric system research and development during that

same time period did not rise to fill the gap. For example, for fiscal years 1996,

1997, and 1998, the funding for DOE’s Transmission Reliability research and development program was zeroed out. This significant reduction in R&D investments has

limited the flow of new technologies, tools, and techniques into the marketplace.

There are other barriers to the acceptance of new electric delivery technologies in

the marketplace. Equipment must be introduced into the electric system in a manner that will ensure safe, reliable, and efficient operation. The electric industry is

reluctant to use new technologies unless their functionality, and especially durability, is ensured. This slows down the process of moving technologies from the laboratory and into the ‘‘tool-kit’’ of electric system planners and operators. Some of the

difficulties stem from problems in managing the risks associated with using new

technologies, risks common to all industries. These technology transfer difficulties

are exacerbated in the electric power sector by a regulatory framework that favors

the status quo and does not typically reward managers for innovation, risk taking,

or entrepreneurial activities. There is a need to work with State commissions to familiarize them with the new technologies and the extent to which their reliability

has been demonstrated.

While this ‘‘re-thinking’’ proceeds, several states have implemented ‘‘price caps’’

as a way to protect consumers from price shocks while the markets adjust and policy makers identify next steps. While attractive to the regulator, price caps tend to

hinder investment because they raise the uncertainty of cost recovery for new plant

and equipment. For example, utilities subject to price caps cannot seek rate increases to recover reliability investment costs; they have to identify offsets from

other aspects of their operation to maintain profitability.

Finally, public concern about the environmental, public health, and safety consequences of electric power has resulted in local or state siting and permitting processes that in many cases have impacted additional capacity. There are numerous

instances over the past decade where projects to modernize the electric grid were

stymied by siting and permitting delays caused by bureaucratic requirements or jurisdictional disputes among states and the Federal Government. This has greatly

hindered new investment despite the existence of a guaranteed rate of return for

investors. However, technologies such as advanced composite conductors that utilize

existing transmission facilities may have a potential advantage over technologies

that would require new rights-of-way.

Administration Action to Address Barriers

The Bush Administration, from the outset, has highlighted the importance of

modernizing America’s electric system. It is one of the most important policy objectives discussed in the President’s National Energy Policy, which was issued in May

2001. One year later, the Department issued The National Transmission Grid

Study, which contains 51 specific recommendations for modernizing the grid and increasing the reliability of America’s transmission system. In September 2002, the

Secretary’s Energy Advisory Board issued the Transmission Grid Solution Report

which outlines steps to streamline transmission siting and permitting and increase

the level of investment in electric transmission facilities. In April 2003, the PresiVerDate 11-MAY-2000 22:27 Apr 21, 2004 Jkt 089419 PO 00000 Frm 00020 Fmt 6633 Sfmt 6621 C:\WORKD\ENER03\092503\89419 SCIENCE1 PsN: SCIENCE1
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dent’s Council of Advisors on Science and Technology issued a report calling for expanded federal investment in electric grid modernization technologies.

Also in April 2003, the Department held the National Electric System Vision

meeting, which resulted in Grid 2030—a National Vision for Electricity’s Second 100

Years, a document that presents industry and DOE’s views on the future of electric

power in America. In July 2003, the Department followed up the ‘‘Grid 2030’’ vision

with the National Electric Delivery Technologies Roadmap meeting, which will soon

result in a document outlining the research, development, and technology transfer

steps that government, industry, and others need to take to make the national vision for the future of the electric system into reality. The U.S. Department of Energy’s website, www.energy.gov, provides access for downloading copies of these documents and reports.

‘‘Grid 2030’’—A National Vision for Electricity’s Second 100 Years

The national vision calls for ‘‘Grid 2030’’ to energize a competitive North American marketplace for electricity. It will connect everyone to abundant, affordable,

clean, efficient, and reliable electric power anytime, anywhere. It will provide the

best and most secure electric services available in the world. Imagine the possibilities: electricity and information flowing together in real time, near-zero economic

losses from outages and power quality disturbances, a wider array of customized energy choices, suppliers competing in open markets to provide the world’s best electric services, and all of this supported by a new energy infrastructure built on superconductivity, distributed intelligence and resources, clean power, and the hydrogen

economy.

Although the precise architecture of America’s future electric system has yet to

be designed, the ‘‘Grid 2030’’ concept has been envisioned to consist of three major

elements:

• A national electricity ‘‘backbone’’

• Regional interconnections which include Canada and Mexico

• Local distribution, mini- and micro-grids providing services to customers from

generation resources anywhere on the continent.

The backbone system will involve a variety of technologies. These include controllable, very-low-impedance superconducting cables and modular transformers operating within the synchronous AC environment; high voltage direct current devices

forming connections between regions; and other types of advanced electricity conductors, as well as information, communications, and controls technologies for supporting real-time operations and national electricity transactions. Superconducting

systems will be able to reduce line losses, assure stable voltage, and expand current

carrying capacities in dense urbanized areas. They will be seamlessly integrated

with high voltage direct current systems and other advanced conductors for transporting electric power over long distances.

Power from the backbone system will be distributed over regional networks. Longdistance transmission within these regions will be accomplished using upgraded,

controllable AC facilities and, in some cases, expanded DC links. High-capacity DC

inter-ties will be employed far more extensively than they are today to link adjacent, asynchronous regions. Regional system planning and operations will benefit

from real-time information on the status of power generation facilities (central-station and distributed) and loads. Expanded use of advanced electricity storage devices will address supply-demand imbalances caused by weather conditions and

other factors. In this grid of the future, markets for bulk power exchanges will be

able to operate more efficiently with oversight provided through mandatory reliability standards, multi-state entities, and voluntary industry entities.

In the ‘‘Grid 2030’’ distribution system, it is envisioned that customers will have

the ability to tailor electricity supplies to suit their individual needs for power, including costs, environmental impacts, and levels of reliability and power quality.

Sensors and control systems will be able to link appliances and equipment from inside buildings and factories to the electricity distribution system. Advances in distributed power generation systems and hydrogen energy technologies could enable

the dual use of transportation vehicles for stationary power generation. For example, hydrogen fuel cell powered vehicles could be able to provide electricity to the

local distribution system when in the garage at home or parking lot at work.

National Electric Delivery Technologies Roadmap

The Roadmap, which is still being finalized by DOE, will call for the collaborative

implementation by government and industry of a five-part ‘‘action agenda’’ to modernize the grid and achieve the ‘‘Grid 2030’’ vision. The action agenda includes:

18

• Designing the ‘‘Grid 2030’’ Architecture—Conceptual framework that guides

development of the electric system from the generation busbar to the customer’s meter

• Developing the Critical Technologies—Advanced conductors, electric storage,

high-temperature superconductors, distributed intelligence/smart controls,

and power electronics that become the building blocks for the ‘‘Grid 2030’’

concept

• Accelerating Technology Acceptance—Field testing and demonstrations that

move the advanced technologies from the laboratory and into the ‘‘tool kit’’

of transmission and distribution system planners and operators

• Strengthening Market Operations—Assessing markets, planning, and operations; improving siting and permitting; and addressing regulatory barriers

bring greater certainty and lower financial risks to electric transactions and

investment

• Building Partnerships—Leveraging stakeholder involvement through multiyear, public-private partnerships; working with States, FERC, and NERC to

address shared concerns

Technologies for Modernizing the Electric Grid

There is a portfolio of technologies that have the capabilities to enhance the reliability and efficiency of the electric grid. Many of these will require further research, development, field testing, and demonstration to lower costs, improve reliability and durability, and demonstrate effective performance. The Appendix, taken

from the National Transmission Grid Study, provides additional details on a wide

range of grid modernization technologies.

Advanced Conductors and New Materials. Desirable properties of new material for

electricity conductors include greater current-carrying capacity, lower electrical resistance, lighter weight, greater durability, greater controllability, and lower cost.

Advances in semiconductor-based power electronics have given rise to new solutions

that allow more power flow through existing assets, while respecting local land use

concerns. Advanced composite materials and alloys are also making an impact and

are being used in new designs for conductors and cables. Diamond technology could

replace silicon and achieve dramatic increases in current density. In addition, scientific discoveries in advanced materials are resulting in new concepts for conductors of electric power. For example, nanoscience is opening new frontiers in the design and manufacture of machines at the molecular level for fabricating new classes

of metals, ceramics, and organic compounds (such as carbon nanotubes) that have

potential electric power applications.

High Temperature Superconductors. High temperature superconductors are a good

example of advanced materials that have the potential to revolutionize electric

power delivery in America. The prospect of transmitting large amounts of power

through compact underground corridors, even over long distances, with minimal

electrical losses and voltage drop, could significantly enhance the overall energy efficiency and reliability of the electric system, while reducing fuel use, air emissions,

and physical footprint. Superconducting technologies can be used in generators, cables, transformers, storage devices, synchronous condensers, and motors—equipment that crosscuts the entire electric power value chain.

Electricity Storage. Breakthroughs that dramatically reduce the costs of electricity

storage systems could drive revolutionary changes in the design and operation of the

electric power system. Peak load problems could be reduced, electrical stability could

be improved, and power quality disturbances could be eliminated. Storage can be

applied at the power plant, in support of the transmission system, at various points

in the distribution system, and on particular appliances and equipment on the customer’s side of the meter.

Communications, Controls and Information Technologies. Information technologies

(IT) have already revolutionized telecommunications, banking, and certain manufacturing industries. Similarly, the electric power system represents an enormous market for the application of IT to automate various functions such as meter reading,

billing, transmission and distribution operations, outage restoration, pricing, and

status reporting. The ability to monitor real-time operations and implement automated control algorithms in response to changing system conditions is just beginning to be used in electricity. Visualization tools are just beginning to be used by

electric grid operators to process real-time information and accelerate response

times to problems in system voltage and frequency levels. Distributed intelligence,

including ‘‘smart’’ appliances, could drive the co-development of the future architecture for both telecommunications and electric power networks, and determines how

19

these systems are operated and controlled. Data access and data management will

become increasingly important business functions.

Advanced Power Electronics. High-voltage power electronics allow precise and

rapid switching of electrical power. Power electronics are at the heart of the interface between energy storage and the electrical grid. This power conversion interface—necessary to integrate direct current or asynchronous sources with the alternating current grid—is a significant cost component of energy storage systems. Additionally, power electronics are the key technology for power flow controllers (e.g.,

Flexible Alternating Current Transmission Systems—FACTS) that improve power

system control, and help increase power transfer levels. New power electronics advances are needed to lower the costs of these systems, and accelerate their application on the network.

Distributed Energy Technologies. Developments to improve the performance and

economics of distributed energy generation and combined heat and power systems

could expand the number of installations by industrial, commercial, residential, and

community users of electricity. Devices such as fuel cells, reciprocating engines, distributed gas turbines and micro-turbines can be installed by users to increase their

power quality and reliability, and to control their energy costs. They can lead to reduced ‘‘upstream’’ needs for electric generation, transmission, and distribution

equipment by reducing peak demand.

Potential Benefits of Grid Modernization

An expanded and modernized grid will virtually eliminate electric system constraints as an impediment to economic growth and in fact will promote and encourage economic growth. As stated in The National Transmission Grid Study, wholesale markets save consumers $13 billion annually, but constraints cost billions

more. Robust national markets for electric power will encourage growth and open

avenues for attracting capital to support infrastructure development and investment

in new plant and equipment. New business models will emerge for both small and

large companies for the provision of a wide variety of new products and services for

electricity customers, distributors, transmitters, and generators.

More energy efficient transmission and distribution will reduce line losses and

help avoid emission of air pollution and greenhouse gases. More economically efficient system operations and the expanded use of demand-side management techniques will reduce the need for spinning reserves, which could also lower environmental impacts. A modernized national electric grid will facilitate the delivery of

electricity from renewable technologies such as wind, hydro, and geothermal that

have to be located where the resources are located, which is often remote from load

centers.

Faster detection of outages, automatic responses to them, and rapid restoration

systems will improve the security of the grid, and make the grid less vulnerable to

physical attacks from terrorists. Greater integration of information and electric technologies will involve strengthened cyber security protections. Expanded use of distributed energy resources will provide reliable power to military facilities, police stations, hospitals, and emergency response centers. This will help ensure that ‘‘firstresponders’’ have the ability to continue operations even during worst-case conditions. Greater use of distributed generation will lessen the percentage of generated

power that must flow through transmission and distribution systems, reducing

strain on the grid. Higher levels of interconnection with Canada, Mexico, and ultimately other trading partners will strengthen America’s ties with these nations and

boost security through greater economic cooperation and interdependence.

Conclusion

The electric grid is an essential part of American life. America has under-invested

in maintenance of the national electric grid and in the development and deployment

of advanced electric delivery technologies. Most of today’s existing infrastructure of

wires, transformers, substations, and switchyards has been in use for 25 years, or

more. The aging of this infrastructure, and the increasing requirements placed on

it, have contributed to market inefficiencies and electricity congestion in several regions. These conditions could lead to higher prices, more outages, more power quality disturbances, and the less efficient use of resources. Jobs, environmental protection, public health and safety, and national security are at risk. We must act now

or risk even greater problems in the future.

In recognition of this, President Bush has asked the U.S. Department of Energy

to lead a national effort to modernize the electric grid. The newly formed Office of

Electric Transmission and Distribution has been given the assignment to do just

that. The Office will work in partnership with the electric industry, states, and

other stakeholders to develop a national vision of the future for America’s electric

20

grid, and a national roadmap of collaborative activities to achieve the vision. The

Office’s activities will include research and development, technology transfer, modeling and data analysis, and policy analysis.

Modernizing the grid will involve time, resources, and unprecedented levels of cooperation among the electric power industry’s many and diverse stakeholders. Neither government nor industry can shoulder these responsibilities alone. The Office

of Electric Transmission and Distribution stands ready to lead this transformation.

21

Appendix

List of Technology Options for Grid Modernization

This appendix, taken from The National Transmission Grid Study, contains a list

of some of the technologies that are being researched and deployed to modernize the

electric grid. The range of potential technologies is enormous and the list presented

is not exhaustive.

• Advanced Composite Conductors: Usually, transmission lines contain steelcore cables that support strands of aluminum wires, which are the primary

conductors of electricity. New cores developed from composite materials are

proposed to replace the steel core.

Objective: Allow more power through new or existing transmission rights of

way.

Benefits: A new core consisting of composite fiber materials shows promise as

stronger than steel-core aluminum conductors while 50 percent lighter in

weight with up to 2.5 times less sag. The reduced weight and higher strength

equate to greater current carrying capability as more current-carrying aluminum can be added to the line. This fact along with manufacturing advances, such as trapezoidal shaping of the aluminum strands, can reduce resistance by 10 percent, enable more compact designs with up to 50 percent

reduction in magnetic fields, and reduce ice buildup compared to standard

wire conductors. This technology can be integrated in the field by most existing reconductoring equipment.

Barriers: More experience is needed with the new composite cores to reduce

total life-cycle costs.

Commercial Status: Research projects and test systems are in progress.

• High-Temperature Super-Conducting (HTSC) Technology: The conductors in

HTSC devices operate at extremely low resistances. They require refrigeration (generally liquid nitrogen) to super-cool ceramic superconducting material.

Objective: Transmit more power in existing or smaller rights of way. Used for

transmission lines, transformers, reactors, capacitors, and current limiters.

Benefits: Cable occupies less space (AC transmission lines bundle three phase

together; transformers and other equipment occupy smaller footprint for same

level of capacity). Cables can be buried to reduce exposure to electric and

magnetic field effects and counteract visual pollution issues. Transformers

can reduce or eliminate cooling oils that, if spilled, can damage the environment. The HTSC itself can have a long lifetime, sharing the properties noted

for surface cables below.

Barriers: Maintenance costs are high (refrigeration equipment is required and

this demands trained technicians with new skills; the complexity of system

can result in a larger number of failure scenarios than for current equipment;

power surges can quench (terminate superconducting properties) equipment

requiring more advanced protection schemes).

Commercial Status: A demonstration project is under way at Detroit Edison’s

Frisbie substation. Four-hundred-foot cables are being installed in the substation. Self-contained devices, such as current limiters, may be added to address areas where space is at a premium and to simplify cooling.

• Below-Surface Cables: The state of the art in underground cables includes

fluid-filled polypropylene paper laminate (PPL) and extruded dielectric polyethylene (XLPE) cables. Other approaches, such as gas-insulated transmission lines (GIL), are being researched and hold promise for future applications.

Objective: Transmit power in areas where overhead transmission is impractical or unpopular.

Benefits: The benefits compared with overhead transmission lines include protection of cable from weather, generally longer lifetimes, and reduced maintenance. These cables address environmental issues associated with EMFs and

visual pollution associated with transmission lines.

Barriers: Drawbacks include costs that are five to 10 times those of overhead

transmission and challenges in repairing and replacing these cables when

22

problems arise. Nonetheless, these cables represent have made great technical advances; the typical cost ratio a decade ago was 20 to one.

Commercial Status: PPL cable technology is more mature than XLPE. EHV

(extra high voltage) VAC and HVDC applications exist throughout the world.

XLPE is gaining quickly and has advantages: low dielectric losses, simple

maintenance, no insulating fluid to affect the environment in the event of system failure, and ever-smaller insulation thicknesses. GILs feature a relatively

large-diameter tubular conductor sized for the gas insulation surrounded by

a solid metal sleeve. This configuration translates to lower resistive and capacitive losses, no external EMFs, good cooling properties, and reduced total

life-cycle costs compared with other types of cables. This type of transmission

line is installed in segments joined with orbital welders and run through tunnels. This line is less flexible than the PPL or XLPE cables and is, thus far,

experimental and significantly more expensive than those two alternatives.

Underwater application of electric cable technology has a long history. Installations are numerous between mainland Europe, Scandinavia, and Great

Britain. This technology is also well suited to the electricity systems linking

islands and peninsulas, such as in Southeast Asia. The Neptune Project consists of a network of underwater cables proposed to link Maine and Canada

Maritime generation with the rest of New England, New York, and the midAtlantic areas.

• Tower Design Tools: A set of tools is being perfected to analyze upgrades to

existing transmission facilities or the installation of new facilities to increase

their power-transfer capacity and reduce maintenance.

Objective: Ease of use and greater application of visualization techniques

make the process more efficient and accurate when compared to traditional

tools. Traditionally, lines have been rated conservatively. Careful analysis

can discover the unused potential of existing facilities. Visualization tools can

show the public the anticipated visual impact of a project prior to commencement.

Benefits: Avoids new right-of-way issues. The cost of upgrading the thermal rating has been estimated at approximately $7,000 per circuit mile, but

reconductoring a 230 kV circuit costs on the order of $120,000 per mile compared with $230,000 per mile for a new steel-pole circuit (Lionberger and

Duke 2001).

Barriers: This technology is making good inroads.

Commercial Status: Several companies offer commercial products and services.

Six-Phase and 12-Phase Transmission Line Configurations: The use of more

than three phases for electric power transmission has been studied for many

years. Using six or even 12 phases allows for greater power transfer capability within a particular right of way, and reduced EMFs because of greater

phase cancellation. The key technical challenge is the cost and complexity of

integrating such high-phase-order lines into the existing three-phase grid.

• Modular Equipment: One way to gain flexibility for changing market and

operational situations is to develop standards for the manufacture and integration of modular equipment.

Objective: Develop substation designs and specifications for equipment manufacturers to meet that facilitate the movement and reconfiguration of equipment in a substation to meet changing needs.

Benefits: Reduces overall the time and expense for transmission systems to

adapt to the changing economic and reliability landscape.

Barriers: Requires transmission planners and substation designers to consider a broad range of operating scenarios.

Also, developing industry standards can take a significant period, and manufacturers would need to offer conforming products.

Commercial Status: Utilities have looked for a certain amount of standardization and flexibility in this area for some time; however, further work remains

to be done. National Grid (UK) has configured a number of voltage-support

devices that use modular construction methods. As the system evolves, the

equipment can be moved to locations where support is needed (PA Consulting

Group 2001).

Ultra-High Voltage Levels: Because power is equal to the product of voltage

times current, a highly effective approach to increasing the amount of power

23

transmitted on a transmission line is to increase its operating voltage. Since

1969, the highest transmission voltage levels in North America have been 765

kV, (voltage levels up to 1,000 kV are in service elsewhere). Difficulties with

utilizing higher voltages include the need for larger towers and larger rights

of way to get the necessary phase separation, the ionization of air near the

surface of the conductors because of high electric fields, the high reactive

power generation of the lines, and public concerns about electric and magnetic field effects.

• HVDC: With active control of real and reactive power transfer, HVDC can be

modulated to damp oscillations or provide power-flow dispatch independent of

voltage magnitudes or angles (unlike conventional AC transmission).

Objective: HVDC is used for long-distance power transport, linking asynchronous control areas, and real-time control of power flow.

Benefits: Stable transport of power over long distances where AC transmission lines need series compensation that can lead to stability problems.

HVDC can run independent of system frequency and can control the amount

of power sent through the line. This latter benefit is the same as for FACTS

devices discussed below.

Barriers: Drawbacks include the high cost of converter equipment and the

need for specially trained technicians to maintain the devices.

Commercial Status: Many long-distance HVDC links are in place around the

world. Back-to-back converters link Texas, WSCC, and the Eastern Interconnection in the U.S. More installations are being planned.

• FACTS Compensators: Flexible AC Transmission System (FACTS) devices use

power electronics to adjust the apparent impedance of the system. Capacitor

banks are applied at loads and substations to provide capacitive reactive

power to offset the inductive reactive power typical of most power system

loads and transmission lines. With long inter-tie transmission lines, series capacitors are used to reduce the effective impedance of the line. By adding

thyristors to both of these types of capacitors, actively controlled reactive

power are available using SVCs and TCSC devices, which are shunt- and series-controlled capacitors, respectively. The thyristors are used to adjust the

total impedance of the device by switching individual modules. Unified powerflow controllers (UPFCs) also fall into this category.

Objective: FACTS devices are designed to control the flow of power through

the transmission grid.

Benefits: These devices can increase the transfer capacity of the transmission

system, support bus voltages by providing reactive power, or be used to enhance dynamic or transient stability.

Barriers: As with HVDC, the power electronics are expensive and specially

trained technicians are needed to maintain them. In addition, experience is

needed to fully understand the coordinated control strategy of these devices

as they penetrate the system.

Commercial Status: As mentioned above, the viability of HVDC systems has

already been demonstrated. American Electric Power (AEP) has installed a

FACTS device in its system, and a new device was recently commissioned by

the New York Power Authority (NYPA) to regulate flows in the northeast.

• FACTS Phase-Shifting Transformers: Phase shifters are transformers configured to change the phase angle between buses; they are particularly useful

for controlling the power flow on the transmission network. Adding thyristor

control to the various tap settings of the phase-shifting transformer permits

continuous control of the effective phase angle (and thus control of power

flow).

Objective: Adjust power flow in the system.

Benefits: The key advantage of adding power electronics to what is currently

a non-electronic technology is faster response time (less then one second vs.

about one minute). However, traditional phase shifters still permit redirection

of flows and thereby increase transmission system capacity.

Barriers: Traditional phase shifters are deployed today. The addition of the

power electronics to these devices is relatively straightforward but increases

expense and involves barriers similar to those noted for FACTS compensators.

24

Commercial Status: Tap-changing phase shifters are available today. Use of

thyristor controls is emerging.

• FACTS Dynamic Brakes: A dynamic brake is used to rapidly extract energy

from a system by inserting a shunt resistance into the network. Adding

thyristor controls to the brake permits addition of control functions, such as

on-line damping of unstable oscillations.

Objective: Dynamic brakes enhance power system stability.

Benefits: This device can damp unstable oscillations triggered by equipment

outages or system configuration changes.

Barriers: In addition the power electronics issues mentioned earlier, siting a

dynamic brake and tuning the device in response to specific contingencies requires careful study.

Commercial Status: BPA has installed a dynamic brake on their system.

• Battery Storage Devices: Batteries use converters to transform the DC in the

storage device to the AC of the power grid. Converters also operate in the opposite direction to recharge the batteries.

Objective: Store energy generated in off-peak hours to be used for emergencies

or on-peak needs.

Benefits: Battery converters use thyristors that, by the virtue of their ability

to rapidly change the power exchange, can be utilized for a variety of realtime control applications ranging from enhancing transient to preconditioning

the area control error for automatic generator control enhancement. During

their operational lifetime, batteries have a small impact on the environment.

For distributed resources, batteries do not need to be as large as for largescale generation, and they become important components for regulating

micro-grid power and allowing interconnection with the rest of the system.

Barriers: The expense of manufacturing and maintaining batteries has limited their impact in the industry.

Commercial Status: Several materials are used to manufacture batteries

though large arrays of lead-acid batteries continue to be the most popular for

utility installations. Interest is also growing in so-called ‘‘flow batteries’’ that

charge and discharge a working fluid exchanged between two tanks. The

emergence of the distributed energy business has increased the interest in deploying batteries for regional energy storage. One of the early battery installations that demonstrated grid benefit was a joint project between EPRI and

Southern California Edison at the Chino substation in southern California.

• Super-conducting Magnetic Energy Storage (SMES): SMES uses cryogenic

technology to store energy by circulating current in a super-conducting coil.

Objective: Store energy generated in off-peak hours to be used for emergencies

or on-peak needs.

Benefits: The benefits are similar to those for batteries. SMES devices are efficient because of their super-conductive properties. They are also very compact for the amount of energy stored.

Barriers: As with the super-conducting equipment mentioned in the passive

equipment section above, SMES entails costs for the cooling system, the special protection needed in the event the super-conducting device quenches, and

the specialized skills required to maintain the device.

Commercial Status: Several SMES units have been commissioned in North

America. They have been deployed at Owens Corning to protect plant processes, and at Wisconsin Public Service to address low-voltage and grid instability issues.

• Pumped Hydro and Compressed-Air Storage: Pumped hydro consists of large

ponds with turbines that can be run in either pump or generation modes.

During periods of light load (e.g., night) excess, inexpensive capacity drives

the pumps to fill the upper pond. During heavy load periods, the water generates electricity into the grid. Compressed air storage uses the same principle except that large, natural underground vaults are used to store air

under pressure during light-load periods.

Objective: This technology helps shave peak and can help in light-load, highvoltage situations.

Benefits: These storage systems behave like conventional generation and have

the benefit of producing additional generation sources that can be dispatched

25

to meet various energy and power needs of the system. Air emission issues

can be mitigated when base generation is used in off-peak periods as an alternative to potentially high-polluting peaking units during high use periods.

Barriers: Pumped hydro, like any hydro generation project, requires significant space and has corresponding ecological impact. The loss of efficiency between pumping and generation as well as the installation and maintenance

costs must be outweighed by the benefits.

Commercial Status: Pumped hydro projects are sprinkled across North America. A compressed-air storage plant was built in Alabama, and a proposed facility in Ohio may become the world’s largest.

• Flywheels: Flywheels spin at high velocity to store energy. As with pumped

hydro or compressed-air storage, the flywheel is connected to a motor that either accelerates the flywheel to store energy or draws energy to generate electricity. The flywheel rotors are specially designed to significantly reduce

losses. Super conductivity technology has also been deployed to increase efficiency.

Objective: Shave peak energy demand and help in light-load, high-voltage situations. As a distributed resource, flywheels enhance power quality and reliability.

Benefits: Flywheel technology has reached low-loss, high-efficiency levels

using rotors made of composite materials running in vacuum spaces. Emissions are not an issue for flywheels, except those related to the energy expended to accelerate and maintain the flywheel system.

Barriers: The use of super-conductivity technology faces the same barriers as

noted above under super-conducting cables and SMES. High-energy-storage

flywheels require significant space and the high-speed spinning mass can be

dangerous if the equipment fails.

Commercial Status: Flywheel systems coupled with batteries are making inroads for small systems (e.g., computer UPS, local loads, electric vehicles).

Flywheels rated in the 100 to 200 kW range are proposed for development

in the near-term.

• Price-Responsive Load: Fast-acting load control is an important element in active measures for enhancing the transmission grid. Automatic load shedding

(under-frequency, under-voltage), operator-initiated interruptible load, demand-side management programs, voltage reduction, and other load-curtailment strategies have long been an integral part of coping with unforeseen

contingencies as a last resort, and/or as a means of assisting the system during high stress, overloaded conditions. The electricity industry has been characterized by relatively long-term contracts for electricity use. As the industry

restructures to be more market-driven, adjusting demand based on market

signals will become an important tool for grid operators.

Objective: Inform energy users of system conditions though price signals that

nudge consumption into positions that make the system more reliable and

economic.

Benefits: The approach reduces the need for new transmission and siting of

new generation. Providing incentives to change load in appropriate regions of

the system can stabilize energy markets and enhance system reliability.

Shifting load from peak periods to less polluting off-peak periods can reduce

emissions.

Barriers: The vast number of loads in the system makes communication and

coordination difficult. Also, using economic signals in real time or near-real

time to affect demand usage has not been part of the control structure that

has been used by the industry for decades. A common vision and interface

standards are needed to coordinate the information exchange required.

Commercial Status: Demand-management programs have been implemented

in various areas of the country. These have relied on centralized control. With

the advent of the Internet and new distributed information technology approaches, firms are emerging to take advantage of this technology with a

more distributed control strategy.

• Intelligent Building Systems: Energy can be saved through increasing the efficient operation of buildings and factories. Coordinated utilization of cooling,

heating, and electricity in these establishments can significantly reduce energy consumption. Operated in a system that supports price-responsive load,

intelligent building systems can benefit system operations. Note: these sysVerDate 11-MAY-2000 22:27 Apr 21, 2004 Jkt 089419 PO 00000 Frm 00029 Fmt 6633 Sfmt 6621 C:\WORKD\ENER03\092503\89419 SCIENCE1 PsN: SCIENCE1
26

tems may have their own, local generation. Such systems have the option of

selling power to the grid as well as buying power.

Objective: Reduce energy costs and provide energy management resources to

stabilize energy markets and enhance system reliability.

Benefits: Such systems optimize energy consumption for the building operators and may provide system operators with energy by reducing load or increasing local generation based on market conditions.

Barriers: These systems require a greater number of sensors and more complex control schemes than are common today. Should energy market access

become available at the building level, the price incentives would increase.

Commercial Status: Pilot projects have been implemented throughout the

country.

• Distributed Generation (DG): Fuel cells, micro-turbines, diesel generators, and

other technologies are being integrated using power electronics. As these distributed resources increase in number, they can become a significant resource

for reliable system operations. Their vast numbers and teaming with local

load put them in a similar category to the controllable load discussed above.

Objective: Address local demand cost-effectively.

Benefits: DG is generally easier to site, entails smaller individual financial

outlay, and can be more rapidly installed than large-scale generation. DG can

supply local load or sell into the system and offers owners self-determination.

Recovery and use of waste heat from some DG greatly increases energy efficiency.

Barriers: Volatility of fuel costs and dependence on the fuel delivery infrastructure creates financial and reliability risks. DG units require maintenance and operations expertise, and utilities can set up discouraging rules for

interconnection. System operators have so far had difficulty coordinating the

impact of DG.

Commercial Status: Deployment of DG units continues to increase. As with

controllable load, system operations are recognizing the potential positive implications of DG to stabilize market prices and enhance system reliability

though this requires a different way of thinking from the traditional, hierarchical control paradigm.

• Power-System Device Sensors: The operation of most of the individual devices

in a power system (such as transmission lines, cables, transformers, and circuit breakers) is limited by each device’s thermal characteristics. In short,

trying to put too much power through a device will cause it to heat excessively and eventually fail. Because the limits are thermal, their actual values

are highly dependent upon each device’s heat dissipation, which is related to

ambient conditions. The actual flow of power through most power-system devices is already adequately measured. The need is for improved sensors to dynamically determine the limits by directly or indirectly measuring temperature.

• Direct Measurement of Conductor Sag: For overhead transmission lines the

ultimate limiting factor is usually conductor sag. As wires heat, they expand,

causing the line to sag. Too much sag will eventually result in a short circuit

because of arcing from the line to whatever is underneath.

Objective: Dynamically determine line capacity by directly measuring the sag

on critical line segments.

Benefits: Dynamically determined line ratings allow for increased power capacity under most operating conditions.

Barriers: Requires continuous monitoring of critical spans. Cost depends on

the number of critical spans that must be monitored, the cost of the associated sensor technology, and ongoing cost of communication.

Commercial Status: Pre-commercial units are currently being tested. Approaches include either video or the use of differential GPS. EPRI currently

is testing a video-based ‘‘sagometer.’’ An alternative is to use differential GPS

to directly measure sag. Differential GPS has been demonstrated to be accurate significantly below half a meter.

• Indirect Measurement of Conductor Sag: Transmission line sag can also be estimated by physically measuring the conductor temperature using an instrument directly mounted on the line and/or a second instrument that measures

conductor tension at the insulator supports.

27

Objective: Dynamically determine the line capacity.

Benefits: Dynamically determined line ratings allow for increased power capacity under most operating conditions.

Barriers: Requires continuous monitoring of critical spans. Cost depends upon

the number of critical spans that must be monitored, the cost of the associated sensor technology, and ongoing costs of communication.

Commercial Status: Commercial units are available.

• Indirect Measurement of Transformer Coil Temperature: Similar to transmission line operation, transformer operation is limited by thermal constraints. However, transformers constraints are localized hot spots on the

windings that result in breakdown of insulation.

Objective: Dynamically determine transformer capacity.

Benefits: Dynamically determined transformer ratings allow for increased

power capacity under most operating conditions.

Barriers: The simple use of oil temperature measurements is usually considered to be unreliable.

Commercial Status: Sophisticated monitoring tools are now commercially

available that combine several different temperature and current measurements to dynamically determine temperature hot spots.

• Underground/Submarine Cable Monitoring/Diagnostics: The below-surface

cable systems described above require real-time monitoring to maximize their

use and warn of potential failure.

Objective: Incorporate real-time sensing equipment to detect potentially hazardous operating situations as well as dynamic limits for safe flow of energy.

Benefits: Monitoring equipment maximizes the use of the transmission asset,

mitigates the risk of failure and the ensuing expense of repair, and supports

preventive maintenance procedures. The basic sensing and monitoring technology is available today.

Barriers: The level of sophistication of the sensing and monitoring equipment

adds to the cost of the cable system. The use of dynamic limits must also be

integrated into system operation procedures and the associated tools of existing control facilities.

Commercial Status: Newer cable systems are being designed with monitoring/

diagnostics in mind. Cable temperature, dynamic thermal rating calculations,

partial discharge detection, moisture ingress, cable damage, hydraulic condition (as appropriate), and loss detection are some of the sensing functions

being put in place. Multi-functional cables are also being designed and deployed (particularly submarine cables) that include communications capabilities. Monitoring is being integrated directly into the manufacturing process

of these cables.

• Direct System-State Sensors: In some situations, transmission capability is not

limited by individual devices but rather by region-wide dynamic loadability

constraints. These include transient stability limitations, oscillatory stability

limitations, and voltage stability limitations. Because the time frame associated with these phenomena is much shorter than that associated with thermal overloads, predicting, detecting and responding to these events requires

much faster real-time state sensors than for thermal conditions. The system

state is characterized ultimately by the voltage magnitudes and angles at all

the system buses. The goal of these sensors is to provide these data at a high

sampling rate.

• Power-System Monitors

Objective: Collect essential signals (key power flows, bus voltages, alarms,

etc.) from local monitors available to site operators, selectively forwarding to

the control center or to system analysts.

Benefits: Provides regional surveillance over important parts of the control

system to verify system performance in real time.

Barriers: Existing SCADA and Energy Management Systems provide lowspeed data access for the utility’s infrastructure. Building a network of highspeed data monitors with intra-regional breadth requires collaboration among

utilities within the interconnected power system.

Commercial Status: BPA has developed a network of dynamic monitors collecting high-speed data, first with the power system analysis monitor

28

(PSAM), and later with the portable power system monitor (PPSM), both

early examples of WAMS products.

• Phasor Measurement Units (PMUs)

Objective: PMUs are synchronized digital transducers that can stream data,

in real time, to phasor data concentrator (PDC) units. The general functions

and topology for this network resemble those for dynamic monitor networks.

Data quality for phasor technology appears to be very high, and secondary

processing of the acquired phasors can provide a broad range of signal types.

Benefits: Phasor networks have best value in applications that are mission

critical and that involve truly wide-area measurements.

Barriers: Establishing PMU networks is straightforward and has already

been done. The primary impediment is cost and assuring value for the investment (making best use of the data collected).

Commercial Status: PMU networks have been deployed at several utilities

across the country.

BIOGRAPHY FOR JAMES W. GLOTFELTY

Jimmy Glotfelty is currently Director of the Office of Electric Transmission and

Distribution at the Department of Energy. This new office was established by Secretary Spencer Abraham to focus attention on the policy and research and development needs of the Transmission and Distribution systems. Prior to this position, he

served as Senior Policy Advisor to Secretary Abraham. He is senior leader in the

implementation of President Bush’s National Energy Policy. He advises the Secretary on policy concerning electricity, transmission, interconnection, siting, and

other areas within the DOE. He works closely with members of Congress and members of the FERC in order to ensure that we continue to move toward competitive

wholesale electric markets. He is also responsible for the development of the national grid study to identify major bottlenecks across the U.S.

Prior to joining the DOE, Jimmy served as Director of Government and Regulatory Affairs for Calpine Corporation’s Central Region. He actively pursued restructured markets and new wholesale and retail markets for new power generation companies in Texas, Louisiana, Alabama, and Mexico. In addition to government affairs,

Jimmy oversaw Calpine’s Central Region public affairs efforts.

From 1994 to 1998, Jimmy served as Director of General Government Policy and

Senior Energy Advisor to Governor George W. Bush. He spearheaded many oil and

gas initiatives, served as the Governor’s office point staff member on both wholesale

and retail electric restructuring in Texas, and oversaw the Texas State Energy Office. In addition to energy issues, Jimmy founded and managed the Governors High

Technology Council, and was responsible for policy initiatives in the telecommunications, banking, housing, and pension arenas.

During his career, Jimmy was Legislative Director for Congressman Sam Johnson

(R–TX) where he was responsible for all legislative operations as well as energy,

banking, and telecommunications issues. Jimmy has also served as Finance Director

for the Republican Party of Texas and as Research Director for the lobby and public

affairs firm Dutko and Associates.

Jimmy resides in Arlington, VA with his wife, Molly, and sons, Chase and Walker.

Chairwoman BIGGERT. Thank you so much.

Mr. Glauthier is recognized. Am I pronouncing that correctly?

Mr. GLAUTHIER. Yes, that is fine. Glauthier. Thank you.

Chairwoman BIGGERT. Glauthier. Thank you.

STATEMENT OF MR. T.J. GLAUTHIER, PRESIDENT AND CEO,

ELECTRICITY INNOVATION INSTITUTE, PALO ALTO, CA

Mr. GLAUTHIER. Thank you, Madame Chair and Members of the

Subcommittee. I am T.J. Glauthier, the President and CEO of the

Electricity Innovation Institute, an affiliate of EPRI, the Electric

Power Research Institute. With me today, also, is Dr. Dan Sobajic,

the Director of Grid Reliability and Power Markets at EPRI. I am

here today testifying on behalf of both organizations. I will summarize my testimony.

29

As you know, EPRI is a non-profit scientific organization formed

by U.S. electric utilities 30 years ago to manage a collaborative research program on behalf of utilities, their customers, and society.

Today, EPRI has more than 1,000 members, including utilities of

all owner types, independent system operators and independent

power producers, and others. Electricity Innovation Institute was

formed two years ago by the EPRI Board of Directors as an affiliated public benefit organization to sponsor long-term strategic R&D

programs through public/private partnerships. Its Board of Directors is primarily composed of independent, bipartisan, public representatives.

Both organizations are already actively engaged in R&D to modernize the electricity grid. Two years ago, in response to the events

of September 11, 2001, an interdisciplinary EPRI team prepared a

preliminary analysis of potential terrorist threats to the U.S. electricity system. Out of this effort grew an infrastructure security initiative, which has undertaken a short-term, tightly focused effort

to identify key vulnerabilities and to design immediately applicable

countermeasures.

In addition, we recently have begun work with the Department

of Homeland Security in which we are bringing utilities and ISOs

together with DHS to help develop a system for them to monitor

the security of the national power grid in real time. Now, after the

power outage of August 14, EPRI is actively supporting the U.S./

Canada joint task force working with DOE and the North American Electric Reliability Council, NERC.

There are several current technologies that could be more widely

used today to increase system reliability and security. First, there

are gaps in the coverage of SCADA and EMS systems, which

should be remedied. Second, system operators need to have greater

visibility into what is happening in neighboring control areas.

EPRI, Department of Energy, and others have demonstrated systems that could do this. Third, State estimators, systems that are

needed for real time management of the grid, are not being fully

utilized in many control areas today. And finally, there are some

technologies that are either ready now or in nearing commercial

availability, which include a Dynamic Thermal Circuit Rating system for improved management of transmission lines, new advanced

high-temperature, lightweight conductors or transmission lines,

which are undergoing testing by EPRI and the Department of Energy as noted by the previous witness, and FACTS devices, Flexible

AC Transmission Systems that can control direct power flows, including loop flows.

All of this is a precursor to the smart grid, which will be the

modernization of the electricity transmission and distribution system to be an intelligent, always on, self-healing grid. It will recognize power system vulnerabilities and alert operators to them, and

in the event of a failure, will automatically island off those areas

to isolate the problem. Smart grid will also support a more diverse

and complex network of energy technologies, including an array of

locally installed distributed power sources, such as fuel cells, solar

power, and combined heat and power systems. This will give the

system greater resilience, enhance security, and improve reliability.

We believe such a smart grid will yield significant benefits both in

30

power—in reducing the cost of power disturbances to the economy

and in enabling a new phase of entrepreneurial innovation, which

will, in turn, accelerate energy efficiency, productivity, and economic growth for the Nation.

We offer four recommendations for the Energy Bill and have submitted legislative language to carry these out. First, to establish

the smart grid as a national priority. This could increase the pace

and level of commitment to the modernization of the electricity

grid. Second, to authorize increased funding for R&D and for an

aggressive program of technology demonstration and early deployment projects. We estimate that this will require increased federal

funding for the Department of Energy on the scale of approximately $1 billion over the next five years, with the private sector

contributing a significant amount of matching funding. Third, recognize a public/private institutional role for the R&D. It is vitally

important that this program be carried out in partnership with the

private sector. It is the industry that will ultimately be responsible

for building, maintaining, and operating the electricity system to

keep the lights on. This is more than a research program; it is an

engineering and operations program on which the country will rely.

And finally, develop a national approach for long-term funding of

deployment, which will require approximately $100 billion over a

decade, $10 billion a year for 10 years. We need a national financing approach that will be effective, fair, and equitable for all parts

of society. We urge the Congress to include language in the Energy

Bill that directs the Administration to work with the industry, the

states, customers, and others to develop a recommendation and report back one year after enactment.

In conclusion, this committee and the Congress can play a pivotal role in leading the modernization of the Nation’s electricity infrastructure for the 21st century.

Thank you, Madame Chair. I welcome any questions.

[The prepared statement of Mr. Glauthier follows:]

PREPARED STATEMENT OF T.J. GLAUTHIER

Thank you, Madam Chair, I am T.J. Glauthier, President and CEO of the Electricity Innovation Institute, an affiliate of EPRI, the Electric Power Research Institute. With me today is Dejan Sobajic, Director of Grid Reliability and Power Markets at EPRI.

As you know, EPRI is a non-profit, tax-exempt, scientific organization formed by

U.S. electric utilities in 1972 to manage a national, public-private collaborative research program on behalf of EPRI members, their customers, and society. Today

EPRI has more than 1,000 members, including utilities of all owner types (both

U.S.-based and international), independent system operators (ISOs), independent

power producers, and government agencies, collectively funding an electricity-related scientific research and technology development program that spans every aspect of power generation, delivery, and use.

The Electricity Innovation Institute (E2I), formed two years ago by the EPRI

Board of Directors as an affiliated non-profit, public benefit organization, sponsors

longer-term, strategic R&D programs through public-private partnerships. Its Board

of Directors is primarily composed of independent, bipartisan, public representatives.

E2I is already actively engaged in modernizing the electricity grid. For example,

with technical support from EPRI, 18 months ago we began a public-private R&D

partnership to design and develop the system of technologies enabling a self-healing,

‘smart grid.’ This partnership involves a number of public and private utility companies, the Department of Energy (DOE), several states, and the high tech industry.

It has one multi-million dollar contract underway, with a team that includes GenVerDate 11-MAY-2000 22:27 Apr 21, 2004 Jkt 089419 PO 00000 Frm 00034 Fmt 6633 Sfmt 6621 C:\WORKD\ENER03\092503\89419 SCIENCE1 PsN: SCIENCE1
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eral Electric, Lucent Technologies and others, to design an ‘open architecture’ for

the smart grid.

EPRI and E2I actively support the dialogue on national energy legislation by providing objective information and knowledge on energy technology, the electricity system and related R&D issues.

I sincerely appreciate the opportunity to address this distinguished Committee on

a subject about which we are all concerned. The electric power system represents

the fundamental national infrastructure, upon which all other infrastructures depend for their daily operations. As we learned from the recent Northeast blackout,

without electricity, municipal water pumps don’t work, vehicular traffic grinds to a

halt at intersections, subway trains stop between stations, and elevators stop between floors. The August 14th blackout also illustrated how vulnerable a regional

power network can be to cascading outages caused by initially small—and still not

fully understood—local problems.

In response to the Committee’s request, my testimony today provides some of

EPRI’s and E2I’s views on technology issues that require further attention to improve the effectiveness and reliability of the Nation’s interconnected power systems.

This testimony will be supplemented with a matrix table as requested by the Committee.

Context for power reliability

Power system reliability is the product of many activities—planning, maintenance, operations, regulatory and reliability standards—all of which must be considered as the Nation makes the transition over the longer-term to a more efficient and

effective power delivery system. While there are specific technologies that can be

more widely applied to improve reliability both in the near- and intermediate-term,

the inescapable reality is that there must be more than simply sufficient capacity

in both generation and transmission in order for the system to operate reliably.

The emergence of a competitive market in wholesale power transactions over the

past decade has consumed much of the operating margin in transmission capacity

that traditionally existed and helped to avert outages. Moreover, a lack of incentives

for continuing investment in both new generating capacity and power delivery infrastructure has left the overall system much more vulnerable to the weakening effects

of what would normally be low-level, isolated events and disturbances.

Two years ago, in response to the events of September 11, 2001, an inter-disciplinary EPRI team prepared the Electricity Infrastructure Security Assessment, a preliminary analysis of potential terrorist threats to the U.S. electricity system. Out of

this effort grew the Infrastructure Security Initiative (ISI), which has undertaken

a short-term, tightly focused effort to identify key vulnerabilities and design immediately applicable countermeasures. The initial phase of the ISI has been completed

and work is now underway to implement some of the technological solutions identified. More recently, E2I and EPRI began work with the Department of Homeland

Security (DHS) to establish the National Electric Infrastructure Security Monitoring

System (NESEC). This system will enable DHS to monitor the security of the national power grid in real time and can be used to identify and diagnose unusual

events that might signal a terrorist attack in its early stages. Such a system could

also be used to monitor grid operations for disturbances with potential to impact reliability.

The electric power industry is one of the most data intensive and computing

power-reliant of all industries, with Supervisory Control and Data Acquisition

(SCADA) systems collecting data and sending control signals over wide geographical

regions, in conjunction with the analytical functions performed by highly computerized Energy Management Systems (EMS).

EPRI is actively supporting the U.S.-Canada Joint Task Force on the power outage of August 14th, working with DOE and the North American Electric Reliability

Council (NERC). Based on information assembled and published by the task force

so far, some basic, bottom-line preliminary implications can be drawn. One is that

better, more complete information about system conditions in the affected region

could have enabled quicker response by the various system operators, which might

have helped avert so widespread an outage.

A significant weakness of the North American power system is that, despite the

computing power that is applied, not all parts of the power system are presently

covered by SCADA and EMS systems. There are gaps in coverage, and some critical

parameters must be computed from other measurements. EPRI strongly recommends that the industry move toward completing the data picture by ensuring

that all transmission facilities down to the 169-kilovolt level are fully measurable

and observable—in real time—for five key parameters: active power, reactive power,

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current, voltage, and frequency. In addition, each of the 150 individual control areas

need to implement complete SCADA coverage for the entire system.

Seeing the bigger picture

System operators also need the capability for a wide-area view of what is happening in neighboring control areas. This would represent a major improvement

over existing conditions, under which operators cannot access the same level of information on neighboring systems that they have on their own system. Two years

ago, in cooperation with NERC, EPRI conducted an R&D project sponsored under

the industry-funded Reliability Initiative, which demonstrated an integrated, realtime visualization of the nationwide interconnected system, incorporating data on

critical operating measurements from each control center, using the Internet for

communication. There are similar demonstration efforts underway by other organizations as well. For a relatively modest cost, such a system could be made available

to all system operators.

A related issue involves interpretation and analysis of the operating data from

SCADA and EMS systems. EMS application software programs known as state estimators are employed to process data and compute values for system parameters

that are not measured. Results are critical for doing more complex analyses, such

as contingency analyses of the impact of losing various system elements, such as

power plants or transmission lines. Yet because of low confidence in the computed

results for real-time decision-making, very few control center EMS state estimators

are fully utilized today. EPRI believes that credible, complete information from operational state estimators is essential for reliability and should be required in all control areas.

Near-term solutions

One relatively simple technology developed by EPRI and successfully demonstrated by several utilities could contribute to improved system reliability by enabling increased confidence of safe loading levels for transmission lines above their

conservative static ratings. By integrating real-time sensor data on ambient temperature, wind speed, and line sag on specific circuits, EPRI’s Dynamic Thermal

Circuit Rating (DTCR) system allows operators to move more power on lines with

reduced risk of thermal overload. DTCR is low-cost and can be quickly deployed on

thermally constrained lines. Such dynamic line ratings, along with more complete

SCADA coverage, would represent key inputs for more probabilistic-based contingency analyses of system instability. Such probabilistic-based analyses could extend

the scope of contingencies considered from the loss of a single transmission line or

generating source (N–1 contingency), which is the current criterion, to the simultaneous loss of multiple lines or generators (N–2 contingency).

On the hardware side of T&D systems, a mid-term solution for increasing the capacity of existing transmission corridors may soon be ready for commercial deployment: advanced high-temperature, low-sag conductors. These advanced conductors

have the potential to increase current carrying capacity of thermally constrained

transmission lines by as much as 30 percent or more. Five new types of aluminum

conductor designs, reinforced or supported with steel or composite material, are

being investigated by EPRI in collaboration with member utilities. One type is already under field test in a project with CenterPoint Energy in Houston; it also

promises more rapid installation, since it has already been demonstrated that the

conductors can be strung while energized. This work complements related ongoing

activity supported by DOE’s Office of Electric Transmission and Distribution, including testing activity at Oak Ridge National Laboratory.

Facing up to loop flows

Numerous knowledgeable power system engineers have warned for many years

that the phenomenon of loop flow would eventually have important implications for

reliability, but those warnings have largely gone unheeded with the emergence of

a competitive, wholesale bulk electricity market. Preliminary indications are that

loop flows of power around the Lake Erie region may have played a role in the Aug.

14th blackout.

Loop flows are a key unresolved issue facing the industry today in terms how the

power system status appears to operators, yet such flows generally are not accounted for in day-to-day operations. Loop flows result from the basic physics of

electricity, which follows all available paths of least resistance, rather than a single

line on a contract path from point A to point B. These loop flows have been present

ever since power grids began to become interconnected, but only recently have loop

flows reached a level sufficient to cause problems. With today’s reduced operating

margins of transmission capacity, they can make the difference between safe operating conditions and system overload.

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Loop flows can be controlled with solid-state power electronics technology, such

as Flexible AC Transmission Systems (FACTS) technology developed by EPRI and

power equipment vendors, but specific operating practices are necessary that require EMS state estimator information to establish proper settings for mitigation.

FACTS technologies deployed in various configurations promise a new dimension of

high-speed control flexibility to change the power system state and react to changes

in ways that we cannot today. However, FACTS technologies are still emerging and

their cost and size must be further reduced through continued R&D efforts before

they are economical for widespread deployment.

In addition to DTCR and improved data exchange standards and system information coverage, other near-term steps that could contribute to improved reliability include improved operator training, both for normal operation under heavy loading

conditions and for service restoration from outages. Operators require more information in order to perform restoration procedures than are required under normal operating conditions. Reiterating the importance of a holistic approach to reliability,

transmission and distribution infrastructure maintenance should be afforded the

same priority as system planning, operations, and energy marketing that are addressed by standing NERC standards committees.

Given that energy legislation now under consideration by the Congress would establish mandatory, enforceable reliability standards under NERC supervision, such

standards should specifically address requirements for the provision of, and compensation for, reactive power for voltage support. Although the significance of this

somewhat arcane component of alternating current transmission is lost on many

people not trained in electrical engineering, its critical importance in the operation

of interconnected systems and long distance transmission cannot be overemphasized. Reactive power is a non-billable, but essential, component of real or active

power that helps maintain voltage and is critical for magnetizing the coils in large

inductive loads so they can start up and begin drawing real power.

Intermediate term measures

Beyond the more immediate steps and technologies available for boosting power

system reliability, development of a number of emerging technologies that are still

not yet ready for commercial deployment could benefit from increased industry and

government support for demonstration efforts. These include the demonstration and

integration of new inter-system communication standards based on open protocols

to enable data exchange among equipment from different vendors, including SCADA

and EMS systems. Two prime examples of such standards are the EPRI-developed

Utility Communications Architecture for connecting equipment from different vendors and the Inter-Control Area Communication Protocol for linking control centers

and regional transmission organizations.

As described more fully below, EPRI’s ultimate vision for the future of power delivery is an electronic, self-healing, adaptive ‘smart’ power grid. However, realizing

this vision fully will require development, demonstration, and integration over the

next decade of key elements that do not yet exist, such as intelligent software to

reconfigure systems to prevent blackouts. Yet features of the self-healing grid of the

future can be demonstrated today using off-the-shelf, recently developed technologies. Such demonstrations could begin providing near-term benefits during the

next several years, before the complete vision of a ‘smart’ grid becomes reality within the next decade.

The Electricity Innovation Institute (E2I), a non-profit affiliate of EPRI established to pursue public-private partnerships for strategic electricity R&D, is proposing just such a partnership to demonstrate Dynamic Risk and Reliability Management (DRRM). The proposed effort would develop and demonstrate a set of realtime tools to enable system operators to see and quickly react to grid conditions that

threaten to cause outages. Unlike existing technologies, the tool set will combine a

picture of real-time vulnerabilities with an assessment of the status of grid components to pinpoint ‘‘hot spots,’’ or areas where equipment failure could precipitate a

widespread outage. Existing tools focus on monitoring the health of equipment or

monitoring the status of the grid, but have not yet been effectively combined into

one tool capable of providing a clear picture of overall risk. DRRM requires all the

previously mentioned short-term improvements in data integrity and coverage in

order to be effective.

E2I is proposing to take maximum advantage of ongoing R&D to develop and implement a working demonstration of DRRM in the shortest possible time. Tools such

as the EPRI-developed Maintenance Management Workstation for transmission substations, Probabilistic Risk Assessment for contingency analyses, Visualization of

transmission conditions via EPRI’s Community Activity RoomΤΜ software, TransVerDate 11-MAY-2000 22:27 Apr 21, 2004 Jkt 089419 PO 00000 Frm 00037 Fmt 6633 Sfmt 6621 C:\WORKD\ENER03\092503\89419 SCIENCE1 PsN: SCIENCE1
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former Advisor expert diagnostic system, and others will be brought together to support DRRM development.

E2I is already engaged with several utility partners anxious to demonstrate

DRRM tools on their transmission systems. The proposed work will require investment of $10 million to $20 million and take approximately two years to complete.

Once demonstrated, DRRM will be designed for rapid deployment by transmission

operators and RTOs. Results of using DRRM would provide the quantitative basis

to support risk-based revisions to contingency analyses, reliability criteria, and operating practices.

Adaptive, self-healing response at the speed of light

The smart grid encompasses both the long distance transmission system and the

local distribution systems. Central to the concept is that it incorporate ubiquitous

sensors throughout the entire delivery system and facilities, employ instant communications and computing power, and use solid-state power electronics to sense and,

where needed, control power flows and mitigate disturbances instantly. The upgraded system will have the ability to read and diagnose problems, and in the event

of a disruption from either natural or man-made causes, it will be ‘self-healing’ by

automatically isolating affected areas and re-routing power to keep the rest of the

system up and running. It will be alert to problems as they unfold, and able to respond at the speed of light.

Another advantage of the smart grid is that it will be able to support a more diverse and complex network of energy technologies. Specifically, it will be able to

seamlessly integrate an array of locally installed, distributed power sources, such

as fuel cells, solar power, and combined heat and power systems, with traditional

central-station power generation. This will give the system greater resilience, enhance security and improve reliability. It will also provide a network to support

new, more energy efficient appliances and machinery, and offer intelligent energy

management systems in homes and businesses. For utilities and their customers,

‘smart’ grid technology could also enable the incorporation of significant amounts of

electricity stored in battery systems, flywheels, compressed-air, and other forms of

storage, when they are economical, for load management, voltage support, frequency

regulation, and other beneficial applications, including providing a buffer between

sensitive equipment and momentary power disturbances.

The enhanced security, quality, reliability, availability, and efficiency of electric

power from such a smart grid will yield significant benefits. It will strengthen the

essential infrastructure that sustains our homeland security. Moreover, it will reduce the cost of power disturbances to the economy, which have been estimated by

EPRI to be at least $100 billion per year—and that’s in a normal year, not including

extreme events, such as the recent outage. Further, by being better able to support

the digital technology of business and industry, the smart grid will also enable a

new phase of entrepreneurial innovation, which will in turn accelerate energy efficiency, productivity and economic growth for the Nation.

The economic benefits of the smart grid are difficult to predict in advance, but

they will consist of two parts. These are stemming the losses to the U.S. economy

from power disturbances of all kinds, which are now on the order of one percent

of U.S. gross domestic product, and taking the brake off of economic growth that

can be imposed by an aging infrastructure.

Electricity Sector Framework for the Future

On August 25, 2003, EPRI released a report on the current challenges facing the

electricity sector in the U.S., outlining a Framework for Action. The report, the Electricity Sector Framework for the Future (ESFF), was completed prior to the August

14 outage, and was developed over the past year under the leadership and direction

of the EPRI Board of Directors.

EPRI engaged more than 100 organizations and held a series of regional workshops, including a diverse group of stakeholders—customers, suppliers, elected officials, environmentalists, and others—in producing the Framework. That dialogue

provided valuable insights into the causes of problems, such as the disincentives for

investment and modernization in transmission facilities, which have become much

more widely recognized since the August outage.

The ESFF report lays out a coherent vision of future risks and opportunities, and

of a number of the issues that must be dealt with in order to reach that future.

It also reflects viewpoints widely shared by the broader electricity stakeholder community that contributed to its development. Its vision of the future will be based

on a transformed electricity infrastructure that is secure, reliable, environmentally

friendly, and imbued with the flexibility and resilience that will come from modern

digital electronics, communications, and advanced computing.

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But to arrive at that future, many parties must take action in the near-term. The

report calls upon Congress to take action in a number of areas, such as establishing

mandatory reliability standards, clarifying regulatory jurisdictions, and helping to

restore investor confidence in the electricity sector so that needed investments can

be made.

EPRI President and CEO Kurt Yeager and I presented a staff briefing on the

Electricity Sector Framework for the Future that was hosted by this committee on

September 11, 2003. The full ESFF report is also publicly available.

Recommended Congressional action

Current legislation under consideration by Congress contains some good provisions in support of technology development, but the national transformation of the

grid is so important that it requires stronger action and support from the Congress

in the energy bill. EPRI submitted specific legislative language, focusing on the

technology and R&D areas that we believe are vital to modernizing the Nation’s

electricity transmission and distribution grid, to the House and Senate leadership

who are currently meeting to discuss H.R. 6. In addition, there are four key areas

of technology policy that the energy legislation should address, as described below:

1. Establish the ‘Smart Grid’ as a national priority

Congress can provide real leadership for the country by establishing the ‘smart

grid’ as national policy and as a national priority in the legislation. By articulating

this as national policy and offering a compelling vision for the country, Congress can

increase the pace and level of commitment to the modernization of the electricity

grid.

That action itself will help to focus the attention of the federal and State agencies

and the utility industry and others in the private sector. By making the smart grid

a national priority, Congress will be sending a clear message that this modernization is critically important in all sectors and in all regions of the country, and that

deployment should be undertaken rapidly.

2. Authorize increased funding for R&D and demonstrations

To carry through with the priority of the smart grid, the legislation should include

significantly increased development funding. In particular, it should contain authorization for significant additional appropriations over the next five years for programs managed by DOE, working in partnership with the private sector.

The Administration has taken some steps in this direction in its earlier budgets,

but this demands even stronger, more targeted action by the Congress. Support is

needed in two areas. One is more extensive R&D in the relevant technologies, needed to provide all the components of the smart grid. The other area is to support an

aggressive program of technology demonstration and early deployment projects with

the states and the industry, to prove out these components, and to refine the systems engineering which integrates all these technologies in real-world settings.

EPRI estimates that this research and demonstration program will require increased federal funding for R&D on the scale of approximately $1 billion, spread out

over five years, with the private sector contributing a significant amount of matching funding. These R&D and demonstration funds represent an investment that will

stimulate deployment expenditures in the range of $100 billion from the owners and

operators of the smart grid, spread out over a decade.

3. Recognize a public/private institutional role for R&D

It is vitally important that the legislation recognize that this R&D and demonstration program should be carried out in partnership with the private sector. The

government can sponsor excellent technical research. However, it is the industry

that will ultimately be responsible for building, maintaining and operating the electricity system to keep the lights on and the computers humming. And as we’ve just

seen, there is little tolerance for error—it has to work all the time—so this is more

than a research program, it is an engineering and operations program on which the

country will rely.

4. Develop an approach for long-term funding of deployment

A national approach is needed to fund the full-scale deployment of the smart grid

throughout the country. The scale of deploying the technology, and doing the detailed systems engineering to make it work as a seamless network, will require significant levels of investment, estimated at $100 billion over a decade.

These implementation costs for the smart grid will be an investment in the infrastructure of the economy. This investment will pay back quickly in terms of reduced

costs of power disturbances and increased rates of economic growth.

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Nevertheless, this is a substantial challenge for an industry that is already under

financial strain, and is lacking investment incentives for the grid. It’s a challenge,

too, because this investment must be new and additional to what the industry and

its customers are already providing to keep the current systems operating. A business-as-usual approach will not be sufficient.

We need a national financing approach or mechanism that will be effective, fair,

and equitable to all parts of society. This will require agreement among the industry, state regulatory commissions, customers and other stakeholders as to how that

should be carried out.

The answer to this will undoubtedly take extended discussions with the various

stakeholder groups. Rather than rush to judgment on one or another specific approach, we urge that Congress include language in the energy bill to direct the Administration to develop an appropriate recommendation. The Administration should

work with the industry, the states, customers, and other to develop its recommendation and report back to Congress at a specific time, no later than one year after enactment.

Conclusion

As noted earlier, the cost of developing and deploying the smart grid for the country should be thought of as an investment in the future—in a secure, reliable, and

entrepreneurial future—that will pay back handsomely over many decades to come

as the energy backbone of the 21st century.

Thank you, Madam Chair. I welcome any questions you may have.

BIOGRAPHY FOR T.J. GLAUTHIER

T.J. Glauthier is President and Chief Executive Officer of the Electricity Innovation Institute (E2I), which sponsors strategic R&D programs through public/private

partnerships. He has managed the start-up of this new organization, which began

full operation in January of 2002. As CEO, he is ultimately responsible for all operations and performance of E2I, including overseeing the activities of the other officers, reporting to the Board of Directors, and coordinating with EPRI and its other

affiliated organizations. In addition, he takes an active role in the strategic direction

of key programs, such as the CEIDS program to develop the new technologies needed to transform the transmission and distribution electricity infrastructure into a

self-healing, ‘smart grid’ to increase security, reliability and flexibility.

Prior to joining the Institute, Mr. Glauthier was the Deputy Secretary and Chief

Operating Officer of the U.S. Department of Energy from 1999 to 2001. In that capacity, he directed the day-to-day management and policy development of the Department’s over 120,000 federal and contractor employees and $18 billion annual

budget. In his COO role, Mr. Glauthier had broad oversight across all four of the

Department’s major lines of business: Defense, Science, Energy, and Environment.

He was also responsible for the corporate offices, such as policy, International Affairs, the CFO, procurement, and personnel. Mr. Glauthier also testified before Congress, coordinated with the White House and other agencies, and represented the

Department and the President in national and international forums.

Before coming to the Energy Department, from 1993 to 1998, Mr. Glauthier

served for five years in the Office of Management and Budget as the Associate Director for Natural Resources, Energy and Science. In that capacity, he and his staff

of 70 served as the key link between the Executive Office of the President and agencies such as the Departments of Agriculture, Energy, and Interior, the EPA, NASA,

NSF, the Army Corps of Engineers, and a number of smaller or independent agencies, such as the Smithsonian Institution, the Kennedy Center, and TVA, together

accounting for over $60 billion in annual discretionary appropriations and over

350,000 federal and contract employees.

Earlier, Mr. Glauthier spent over twenty years in management consulting. For

most of that time, he was with Temple, Barker & Sloane, Inc., where he began as

a specialist on corporate and financial planning for Fortune 500 companies, and

later became the Vice President in charge of the firm’s Public Policy and Management Group.

Immediately prior to joining the Clinton Administration, Mr. Glauthier spent

three years as Director of Energy and Climate Change at the World Wildlife Fund,

where he dealt with technology transfer, the climate change treaty, and the 1992

Earth Summit in Rio de Janeiro.

Mr. Glauthier is a graduate of Claremont Men’s College and the Harvard Business School.

Chairwoman BIGGERT. Thank you very much.

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And now, Dr. Smith. Would you turn on your microphone, so that

the green light is lit?

STATEMENT OF DR. VERNON L. SMITH, NOBEL LAUREATE,

PROFESSOR AT GEORGE MASON UNIVERSITY

Dr. SMITH. Thank you, Madame Chair. It is a pleasure for me to

be here and to have the opportunity to make, perhaps, a small contribution to a very large problem.

To me, the basic problem is not at the transmission level; it is

in the—it is between the substation and the end-use consumer.

That is the area in the entire electric power system, which has

been a—is still—basically is locked in 1930’s technology, and there

is no incentive there to innovate. And I—to me, and that gives us

an extremely inflexible demand side system.

And it is—for example, it is very vulnerable. You couldn’t—I

can’t imagine designing a more vulnerable electric power system to

terrorist attack. You are from Chicago. Suppose terrorists take out

half of the supply of energy to Chicago. Utilities have no option but

to shed—but to turn off half of the substations. It is much better

to turn off the lowest half priority of power, not everything below

a substation. If—and it is fundamentally an incentive problem, an

incentive to innovate prices and an incentive to develop the kinds

of technologies that both fit consumer preferences and enable the

energy suppliers to profit from providing those services.

I want to show a slide.

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And I—let me apologize for the old technology here, but it is—

this is a—this slide shows the variation in just the marginal cost

of energy in the Midwest. This is a period in the ’80’s in a hot August week. It is the hourly variation and the cost of just the energy

component of people’s bills. At the time, the energy component of

people’s bills would have been a flat, roughly three cents a kilowatt. And you will notice that actual costs are peaking as high as

8c cents and as low as 1c cents. That is the kind of variability you

have when the system is strained. And it—whether it is strained

enough to take out transmission lines still, it happens very, very

commonly. Notice here what that means is that the peak users are

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imposing costs on the system that are far larger than the price

they are paying. In effect, the utility is subsidizing peak consumption. It is sending signals—a signal that says dry your clothes at

3 p.m. in the afternoon, okay. And off-peak, the—basically the

users are being taxed, because they are paying a price much above

the marginal cost of producing the energy.

If I could have the second slide, please.

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I want to show you the effect of laboratory experiments comparing—this is a—these are two-sided spot markets made by

human subjects who profit from—the wholesale buyers are profiting by trying to buy power low and reselling it to customers. Generator owners are attempting to profit by selling power above their

cost of generation. It is a two-sided market. And what we are comparing is the effect of demand side bidding where you can interrupt

16 percent of the peak demand, that is about 20 or 24 percent, I

have forgotten, of the shoulder demand. And the red here shows

the tremendous increases in prices when it is just a one-sided market without the opportunity for the wholesale buyers to strategically bid into that market and interrupt a portion of their demand

and an attempt to keep prices down. Blue shows four different experiments where wholesale buyers are actively bidding in their own

interests, and you will notice that those prices are far lower. Also,

they spike a whole lot less. The energy spiking on peak is coming

from generators bidding into a market with a completely inflexible

demand. And all over the world, you see those spikes.

Now what is to be done? Well, my view is that you need to open

up that portion of the grid below the substation level for innovation

and competition. That means people attempting to make money by

introducing technologies that are saving to give customers a break

on their peak charges, and also, of course, there are possibilities for

distributed generation to be installed closer to the customer and to

bypass the entire grid and get below the substation level. And I

think the—that means allowing alternative energy suppliers to

come in and sell energy to the customers of the local wires company. That means the inference have to get access to the wires in

order to install the technologies that their customers prefer. The

local wires company is not well motivated to let people in there.

Madame Chairman, you, perhaps, remember when you bought a

new telephone for your home, you had to buy it from the American

Telephone and Telegraph Company. You were not allowed to buy

a telephone separately and install it in your house. And furthermore, Ma Bell, at the time, gave you a choice. When things really

opened up, you got your choice between black, white, and red. All

right. All of that has changed.

The other thing that you couldn’t do under the government-sanctioned monopoly of AT&T is let anyone in your house, any repairman in your house to fiddle with the telephone wires. That person

had to come in an AT&T truck. All of that has changed. Arguments

were made at the time. We can not let people in there to fiddle

with the wires, because it is the integrity and security of the bid

we are worrying about. Not any—I mean, you know, that is real

complicated that red, green, and yellow wire in there, and it has

to be handled by AT&T. That is the situation we face in the local

distribution utilities. And I think until that is opened up, we are

going to continue to have problems.

Thank you.

[The prepared statement of Dr. Smith follows:]

PREPARED STATEMENT OF VERNON L. SMITH

Testimony will address the following four questions:

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1) Briefly describe the market structure for the electricity sector as it existed

15 years ago and contrast it with the structure today.

2) What barriers currently prevent wider adoption of commercially available

energy technologies? What policy choices would be most conducive to greater

adoption of these technologies?

3) How is uncertainly affecting the economics of investment in the electricity

sector? How can we structure a market to ensure reliable electricity at the

lowest cost?

4) What are the incentives for utilities to invest in transmission research and

development? How can we encourage investment in research and development in a highly competitive electricity sector?

Responses:

Q1: The market structure at the retail level, which is where the system is rigid

and unresponsive, has not changed in 15 years. Essentially from the neighborhood

substation to the end use customer, we are talking about 1930’s technology. Two

slides:

Slide 1; Variability of wholesale energy cost during a hot August week in the Midwest (1980s), showing the effect of a fixed energy retail price: Customers pay less

than the cost of their energy consumed on peak, and the loss to the utility is therefore

a subsidy that encourages consumption; customers pay more than the cost of their

energy off peak, and are therefore taxed to discourage consumption.

Slide 2; Effect of profit-motivated human subjects who bid their demand in to the

spot market along with supply-side bids by generation firms who have market

power on the shoulder demand periods. Sixteen percent of peak (20 percent of shoulder) demand is interruptible. Market power is neutralized by the wholesale demand

side buyers; price spikes all but disappear; and prices are much lower, more nearly

reflecting the dynamic changes in wholesale costs.

Q2: The barriers are the continuation of 85 years of regulation of the local distribution franchised monopoly preventing free entry by alternative suppliers of ENERGY. Regulation protects the right of the local distributor to tie the sale of energy

into the rental of the wires.

It’s like legally franchising the right of the rental car companies to require their

customers to buy all their gasoline from the rental car company’s own supplies. But

of course the technologies required are very different in electricity.

Two suggested policies:

1. Permit free entry by qualified energy suppliers; over time phase out energy

sales by the local wires companies.

2. Allow entrants access to the wires between the end user outlet, and the substation to install technologies that fit consumer preferences, and allow interruption of peak time energy deliveries when its cost is more than individual

customers want to pay. Similarly, entrants can compete to provide customers

off peak discounts.

Q3: At the retail level no one knows what menu of dynamic pricing contracts and

corresponding technologies will fit individual consumer circumstances, and emerge

as profitable for retail energy suppliers. Moreover, no one knows what new lower

cost technologies will emerge once there is an incentive for firms to innovate between the substation and the end use consumer. This is normal market investment

uncertainty. The structure needed to deal with that uncertainty is indicated in the

two policies recommended in Q2.

Q4: The first order of business is not at the transmission level. Transmission is

strained and stressed by inflexible peak consumption tending to exceed energy supplies. Transmission capacity is entirely determined by peak requirements, but at the

consumption level there is neither the technology nor the competitive incentive to

implement a dynamic price responsive demand that limits peak consumption, and

reduces peak transmission requirements. More expensive transmission capacity

could easily do more harm than good by casting in concrete the downstream rigid

retail incentive demand structure.

The retail energy supply sector is not now close to being highly competitive. When

it is, the supplying firms will have all the incentive they need to innovate and profit

thereby.

42

Demand, Not Supply

Wall Street Journal

BY VERNON L. SMITH AND LYNNE KIESLING

Immediately following the failure of the electrical network from Ohio to the

Northeast Coast, a cascade of rhetoric swept across news networks, blaming the

blackout on an antiquated grid with inadequate capacity to carry growing demand

for electrical energy. As in the California energy debacle, we are hearing the familiar call on government to ‘‘do something.’’

The California government response—doing something—left the state with a staggering and unnecessary level of debt. Meanwhile, without any additional action by

the state, the demand and energy supplies in California have returned to their normal and much less stressful levels and wholesale prices are back to normal. There

is no news except good news, but have we gained any deep understanding of power

system vulnerability and its efficient cure from this event?

Before Congress and the administration begins to follow the California model and

throw other people’s money at the power industry, let’s have some sober and less

frantic talk.

A systematic rethinking of the power demand and supply system—not just transmissions lines—is required to bring the energy industry into the contemporary age.

Eighty-five years of regulatory efforts have focused exclusively on supply—leaving

on dusty shelves proposals to empower consumer demand, to help stabilize electric

systems while creating a more flexible economic environment.

Under these regulations, a pricing system has developed that is so badly structured at the critical retail level that if it were replicated throughout the economy,

we would all be as poor as the proverbial church mouse. Retail customers pay averaged rates, making their demand unresponsive to changes in supply cost. Without

dynamic retail pricing, no one can determine whether, when, where or how to invest

in energy infrastructure. Impulsive proposals to incentivize transmission investment, without retail demand response, puts the cart before the horse and risks expensive and unnecessary investment decisions, costly to reverse.

At the end-use customer level, the demand for energy is almost completely unresponsive to the hourly, daily and seasonal variation in the cost of getting energy

from its source—over transmission lines, through the substations and to the outlet

plugs. The capacity of every component of that system is determined by the peak

demand it must meet. Yet that system has been saddled with a pure fantasy regulatory requirement that every link in that system at all times be adequate to meet

all demand. Moreover, the industry has been regulated by average return criteria,

and average pricing.

When the inevitable occurs, as in California, and unresponsive demand exceeds

supply, demand must be cut off. Your local utility sheds load by switching off entire

substations—darkening entire regions—because the utility has no way to prioritize

and price the more valuable uses of power below that relic of 1930s electronic technology. This is why people get stuck in elevators and high-value uses of power are

shut off along with all the lowest priority uses of energy. It’s the meat-ax approach

to interrupting power flows. Between the substation and the end-use consumer appliance is a business and technology no-mans-land ripe for innovation.

When a transmission line is stressed to capacity, and its congestion cost spikes

upward, the market is signaling the need for increased capacity in any of three components of the delivery system: increased investment in technologies for achieving

price responsive demand at end use appliances; increased generation nearer to the

consumer on the delivery end of the line; or increased investment in transmission

capacity.

What is inadequately discussed, let alone motivated, is the first option—demand

response.

Many technologies are available that provide a dual benefit—empowering consumers to control both energy costs and usage while also stabilizing the national

energy system. The simplest and cheapest is a signal controlled switch installed on

an electrical appliance, such as an air conditioner, coupled with a contract that pays

the customer for the right to cut off the appliance for specified limited periods during peak consumption times of the day. Another relatively inexpensive option is to

install a second, watt-hour meter that measures nighttime consumption, when energy usage is low, coupled with a day rate and a cheaper night rate. More costly

is a time-of-use meter that measures consumption in intervals over all hours of the

day, and the price is varied with delivery cost throughout the day. Finally, a load

43

management system unit can be installed in your house or business that programs

appliances on or off depending on price, according to consumer preferences.

More important, better and cheaper technologies will be invented once retail energy is subject to free entry and exit. No one knows what combination of technology,

cost and consumer preferences will be selected. And that is why the process must

be exposed to the trial-and-error experiment called free entry, exit and pricing. As

in other industries, investors will risk their own capital—not your tax dollars or a

charge on your utility bill—for investments that fail. Also, as in other industries

with dynamically changing product demand, competition will force prices to be

slashed off-peak, and increased on-peak to better utilize capacity.

Together with demand response technologies, a simple regulatory fix can give new

entrants the incentive to provide customers with attractive retail demand options.

Local regulated distribution utilities have always had the legally and jealously protected right to tie in the rental of the wires with the sale of the energy delivered

over those wires. But these are distinctly separable activities. Just as rental car

companies are separate from gas stations, electricity can be purchased separately

from the company that delivers it to you—provided only that they can access the

wires to install metering, monitoring and switching devices that fit the budget/preferences of individual consumers.

Remember when Ma Bell would not let you buy any telephone but hers, and

would not let you admit any licensed electrician into your house to access the telephone wires except those arriving in her service truck? All that has changed for the

better in telecommunications, but we are still stuck in a noncompetitive world in

the local utility industry.

* * *

Against the backdrop of the wars in Iraq and Afghanistan, the East Coast blackout stimulated de ́ja` vu speculation of Sept. 11 and fears of shadowy operatives bent

on disaster. Since 2002, the Critical Infrastructure Protection Project at George

Mason University has worked under a Department of Commerce grant to integrate

the study of law, technology, policy and economics relating to the vulnerability of

key U.S. infrastructure. Prime among this continuing research is investigation of

the susceptibility of the national power grid.

As it turns out, terrorist speculation, though false, did not fall far from the truth.

If you were to design an electrical system maximizing vulnerability to attack, it is

hard to imagine a better design than what has evolved in response to regulation.

If a terrorist attack took out half the energy supply to Chicago, the only viable response would be to shut down half the substations. Demand response would allow

a prioritization of energy use, shutting down only the lowest priority of power consumption while supplying high value uses—such as production facilities, computer

networks, ports, airports and elevators. Power systems badly need the flexibility to

selectively interrupt lowest value uses of power while continuing to serve higher

value uses. Retail price responsiveness in a competitive environment provides such

a priority system.

The implementation of retail demand response in the electric power industry

would provide a wide range of benefits including lower capital and energy costs,

fewer critical power spikes, consumer control over electricity prices, and the environmental benefits gained by empowering consumers to use electricity more wisely. Despite Milton Friedman’s admonition, by adding increased flexibility to the electricity

grid and sparing critical infrastructure from shutdown, demand response creates a

more efficient and resilient economic structure while providing more robust security

as a free lunch.

Mr. Smith, on leave at the University of Alaska Anchorage, is professor of economics and law at George Mason and the 2002 Nobel laureate in economics. Ms.

Kiesling is senior lecturer in economics at Northwestern and director of economic

policy at the Reason Foundation.

Updated August 20, 2003

44

BIOGRAPHY FOR VERNON L. SMITH

Vernon L. Smith was born in the flat plains of Wichita, Kansas during the boom

years preceding the Great Depression, January 1, 1927. Born to politically active

parents—and an avowedly Socialist mother who revered Eugene Debs—Vernon

Smith’s early ideological indoctrination would prove pivotal to his attraction to the

economic sciences.

While earning his bachelor’s degree in electrical engineering at the California Institute of Technology in 1949 Smith took a general economics course. Intrigued,

Smith pursued the science, receiving a Masters in Economics from the University

of Kansas in 1952 and a Ph.D. from Harvard University in 1955.

Dr. Smith’s initial training in the hard sciences lead him to pursue the application

of the scientific method in his chosen profession, and social science, of economics.

Predisposed to have the heart of a socialist, Dr. Smith expected to prove the inefficiencies of market mechanisms when he conducted his first economic experiments

in 1956 at Purdue University, using his students as subjects. However, Dr. Smith’s

experiments—testing economic concepts and theories under controlled conditions—

instead overwhelmingly demonstrated to him the clear efficiencies of markets.

Smith found that even with very little information and a modest number of participants, subjects converge rapidly to create a competitive equilibrium.

Specifically, Smith’s experiments proved large numbers of perfectly informed economic agents were not prerequisites for market efficiency—a radical departure from

conventional economic thought. Smith compiled his early experiments and in 1962,

while a Visiting Professor at Stanford University, published his findings in the

Journal of Political Economy. The article, ‘‘An Experimental Study of Market Behavior,’’ is today considered the landmark paper on experimental economics.

Continuing his work, again at Purdue University, Smith conducted more and

more experiments while also becoming well known as an expert in capital theory

formation and an early pioneer in the field of environmental economics. Widening

the interest in academia, Smith continued to research and teach experimental methods, as well as explore new avenues, at Brown University, University of Massachusetts, University of Southern California, California Institute of Technology and the

University of Arizona.

Displaying an unusual breadth of academic understanding and application, Smith

has published and co-published numerous seminal works exploring, and defining,

experimental economics as well as other economic disciplines. His ‘‘The Principle of

Unanimity and Voluntary Consent in Social Choice’’ published in the Journal of Political Economy in 1977 initiated the systematic study of institutional design for

public choice decisions. The 1982 ‘‘Microeconomic Systems as an Experimental

Science’’ in the American Economic Review marked the still adhered to methodology

for experimental economics. His 1982 ‘‘A Combinatorial Auction Mechanism for Airport Time Slot Allocation’’ in the Bell Journal of Economics provided a real-world

application of experimental economics on economic systems design. The 1988 ‘‘Bubbles, Crashes and Endogenous Expectations in Experimental Spot Asset Markets’’

published in Econometrica examined stock market bubbles and rational expectations. The 1994 ‘‘Preferences, Property Rights and Anonymity in Bargaining Games’’

in Games and Economic Behavior started the systematic study of personal exchange.

At the same time the slow but steady development in experimental economics

begun by Smith in the 1950s and 1960s was superseded by accelerated development

in the 1970s and 1980s. After establishing himself as the field’s pre-eminent researcher, Smith collaborated with several noted economists to refine and improve

his subject.

From Smith’s foundation of research, the modern experimental methods in economics began to gain acceptance. The research expanded to include the economic

performance of many real-world institutions. Attempts to apply laboratory experimental methods to policy problems became systematic. The convergence properties

of multiple markets were discovered. Conspiracy, price controls and other types of

market interventions were examined experimentally for the first time. New forms

of markets were studied, such as methods for deciding on programs for public broadcasting. All this research stems from the initial contributions of Dr. Vernon Smith.

Current research is focused on the design and testing of markets for electric

power, water and spectrum licenses and a new field ‘neuroeconomics’ which analyzes the impact of brain functions on economic decision-making. As well, Dr. Smith

and his colleagues have worked with the Australian and New Zealand governments

on privatization issues, developed market designs for the Arizona stock exchange,

and designed an electronic market for water in California.

45

Dr. Smith’s groundbreaking work has led to an explosion in the application of laboratory experimental methods. Volumes of experimental papers are being published

each year and the number of experimental laboratories are growing rapidly around

the world. ICES is now the preeminent facility serving as a model for experimental

economic and laboratory development throughout the world.

On December 10, 2002 Dr. Smith received the Bank of Sweden Prize in Economic

Sciences in Memory of Alfred Nobel—the Nobel Prize in Economics—from His Majesty Carl XVI Gustaf for ‘‘for having established laboratory experiments as a tool

in empirical economic analysis, especially in the study of alternative market mechanisms.’’

Chairwoman BIGGERT. Thank you very much. I certainly do remember those phones. I think we had to lease them, too, and then

finally you could purchase them. I hate to admit it, but I do remember.

Mr. Casten, if you would like to begin.

STATEMENT OF MR. THOMAS R. CASTEN, CEO, PRIVATE

POWER, LLC, OAK BROOK, IL; CHAIRMAN, WORLD ALLIANCE

FOR DECENTRALIZED ENERGY

Mr. CASTEN. Madame Chairwoman, Members of Congress, thank

you for the opportunity to present my views on preventing blackouts while saving money and reducing pollution.

We have the technology to greatly improve the U.S. power system. Building local power that recycles presently wasted energy

will reduce system vulnerability, reduce future capital expenditures

for power, reduce energy costs/pollution, greenhouse gas emissions,

and significantly improve the economy. What is not to like?

But all of the technologies that generate power locally and thus

lower the throughput on existing wires are discouraged and, indeed, stopped by many barriers. We have heard much about an industry vision of a smart and self-healing grid. And I think those

are welcome changes, but that view focuses on modernizing the

grid, and it falls short on modernizing the world view that continues to treat central generation as optimal. Pursuing this obsolete central generation vision will lead to more wires we don’t need,

will raise the cost of power to consumers, and will only modestly

lessen system vulnerability.

Finally, I would like to note that Isabel was the ninth area-wide

blackout in the last seven years, which is still going on. The only

unique thing about the blackout in question is that it was not attributed to an act of God. And so we are—we can chase some culpable individual, but in the western states, a tree branch knocked

out 18 states six years ago and on and on.

Now on background, responding to your questions. I have been

attempting to change the way the world makes power for 25 years,

believing that we can no longer afford the waste inherent in remote

generation. The U.S. power system reached the pinnacle of its efficiency in 1959 when it converted 33 percent of the fuel that it

burned into delivered energy. It has not increased one percentage

point in the ensuing four decades, despite of all of the technology.

I founded Trigen Energy Corporation, ultimately taking it public

on the New York Stock Exchange, to correct this. The 56 power

plants that we built used a variety of fuels: biomass, coal, oil, natural gas, and waste fuels. They ranged from a single megawatt to

over 200 megawatts. In total, we made more power than the single

largest nuclear plant in the United States, all locally. Each of these

46

plants recycled the normally wasted heat. Operating in 18 states,

including Pennsylvania, Georgia, Michigan, Tennessee, and Indiana, we achieved our mission of producing heating, cooling, and

electricity with less than half the fossil fuel and less than half the

pollution of conventional generation. If the system was anywhere

near optimal, it would not be possible to achieve those kind of results.

After an unwelcome buyout of Trigen, I joined with others to

form Private Power to purchase and operate projects that recycle

energy. We recently announced agreement to acquire six projects in

northern Indiana. They are within an hour’s drive of Hinsdale, Madame Chairman, and I would be delighted to—and honored to have

you and your staff visit those projects. And I think it would be useful.

We generate 460 megawatts of power with virtually no fossil

fuel. One of the projects recovers heat from 368 coke ovens, uses

utility style technology to convert that into 100 megawatts of power

and 200,000 pounds of steam. And all of that power stays right at

the steel mill. Three of the projects burn blast furnace gas that had

been flared and create another 300 megawatts of power. One conventional project burns gas in a gas turbine, but achieves 2c times

the efficiency of central power, because we take all of the heat and

use it for the cold rolling process at the steel mill.

The projects have won several environmental awards. They significantly reduce greenhouse gases, and they save the four steel

companies over $100 billion a year. Moreover, today’s concern

about blackouts and system vulnerability, these projects ease the

transmission loads and reduce line losses to other customers. All of

the power stays home, is used by the steel mills, and in times of

high system demand, these projects automatically adjust their output to support the voltage on the back end of the lines, and that

allows the wires to carry more power with fewer losses to other

consumers.

We have analyzed the data that EPA keeps of flare gas, of heat

exhausted from industrial processes and of pressure drop that is ignored by our central power system. We find that this waste energy

in the United States, if recycled, could produce between 45,000 and

90,000 megawatts of fossil fuel-free, pollution-free power. That is

the equivalent of 90 nuclear plants with no environmental problems. Another 300 gigawatts, which would be about half of the U.S.

power demand, and all of the projected 20-year load growth could

be generated by burning fuel locally where you could take the normally wasted heat and recycle it to avoid putting more fuel into a

boiler.

In summary, local power has these benefits. It does not need

transmission wires. It is thus cheaper to construct. It avoids the

nine percent average line losses. It recycles waste heat inherent in

all power generation. Or even better, it uses industrial waste heat

to generate the power. EPA just completed a study that combined

heat and power emits 1/20 of the pollution of the average central

power station. We have estimated that the $390 billion U.S. heat

and power system could slash $100 billion a year out of its costs

by deploying local power.

47

You asked what the barriers are to local power, and I will be

quick about them. I have summarized them later. It is illegal to

run a private wire across the street in all 50 states. Rate commissions allow their utilities to charge for 100 percent of the wires and

generation for backup, even though on an actual basis, it is about

two percent. It is like charging $100 for $100 of life insurance.

There is no locational value given in where the power is located.

In Texas, it costs the same to move power across the street as the

whole way across the state, discouraging the local power. There are

all of the policy decisions, I am sad to say, including this committee, use the wrong metric. You talk about what is the cost of

the power at the generator. What is the capital cost of the generator? It is an irrelevant question. What is the cost at the consumer

after you pay for the wires? Local power doesn’t need wires. The

environmental policy does not recognize the output and therefore

gives no encouragement to recycling energy.

What are the policy choices that you could follow to encourage

local power? I think most important, use the right metric and talk

about the real thing: what does it cost at the consumer? Secondly,

I think Congress should remove the ban on private wires. This

would give all local power developers a fair chance to get a reasonable price on using existing wires to move their power. There

wouldn’t be any new wires built, but we would have a fair discussion. You need to demand standard interconnection rules without

the excessive and bogus safety concerns of the red and green wires

that Dr. Smith refers to. I think you should encourage or demand

recycled power. I would strongly support a clean portfolio standard

that mandates that a growing percentage of power come from recycled energy, and that will encourage local power. That is where it

all is. And finally, I would suggest that you have the national laboratories shift their focus from new generation technology to focusing on the interconnection issues and getting deployment of the

technologies that are already there.

Finally, you asked what the local deployment differences are.

The U.S. generates only six percent of its total power locally, all

of the rest coming from remote plants. By contrast, Denmark, Finland, and the Netherlands generate over 40 percent of their power

out of local plants, saving wires and making it cheaper. Within the

U.S., the picture is equally diverse. Three states, South Carolina,

South Dakota, and Kentucky, have virtually no local generation. At

the other extreme, Hawaii produces 33 percent. California, I think,

is about 25 percent local power. New York and Maine are in the

high teens. The differences are in State encouragement of wider

choices.

The high local power states encourage local power with requirements for utilities to purchase the power at full cost. They tackled

interconnection rules. They tailored their environmental management to output standards and rewarded efficiency. And they have

provided grants to break old paradigms. The states with little local

power have laws preventing third parties from generating power on

site and selling it. They give no locational value to power.

In conclusion, I note that Congress faces a seemingly unpleasant

task. The power industry begs help to build more wires. The papers

are asking for $100 billion for improved grid and wires. They ask

48

for new eminent domain rights so that the wires can slash across

our parks and backyard. I think this will raise prices. It will annoy

the voters, and it will largely fail to address system vulnerability

or to mitigate power system related problems. There is a better solution. Local generation operation options are technically right.

They are environmentally superior. They are at least twice as efficient as the average central generation. My work in Trigen and

now Private Power has proven the value of these systems. I think

that if Congress lifts the many barriers, everyone will follow.

Thank you.

[The prepared statement of Mr. Casten follows:]

PREPARED STATEMENT OF THOMAS R. CASTEN

Madam Chairwoman, Congresspersons, Ladies & Gentlemen:

My name is Tom Casten and I am the Chairman and CEO of Private Power in

Oak Brook, Illinois. I appreciate the opportunity to present my views on preventing

blackouts while saving money and reducing pollution. We have the technology, but

block its use because of a now obsolete worldview. We have heard much about an

‘‘industry consensus vision’’ for a smart, self-healing grid. This view focuses on modernizing the grid, but falls short on modernizing the worldview and leads to more

wires we don’t need. Applying three (3) simple principals will optimize the power

system. The principals are:

• Build local power

• Build smaller

• Recycle waste energy.

Blackouts blackouts everywhere

On August 14th, around 2:00 PM, a 31-year-old, 650 megawatt Ohio power station

failed. Transmission controllers struggled to route power from remote plants, overloading transmission lines. At 4:06, a 1200-megawatt transmission line melted,

starting a failure cascade. Lacking local generation, system operators could not

maintain voltage and five nuclear plants tripped, forcing power to flow from more

remote plants and overloaded regional lines. By 4:16 PM, the northeastern U.S. and

Ontario, Canada lost power.

Before the even more recent blackouts associated with Hurricane Isabelle that

many of you have experienced, the August 14th blackout was the eighth area-wide

loss of power in seven years. It differed from the prior seven blackouts in one respect—the cause was not seen as an act of God. Herewith the recent record:

1996— A falling tree branch in Idaho led to a failure cascade, blacking out 18

states.

1997— An ice storm in Quebec downed transmission lines and blacked out

much of New England.

June 1998— A tornado downed a Wisconsin power line leading to rolling

brownouts east of Mississippi.

2000— Low water and a failed nuclear plant caused a power crisis in California

with a month of brownouts and rolling blackouts. This nearly bankrupted California.

1999–2002— Three separate ice storms caused large area blackouts in Oklahoma.

2003— A thirty-one year old coal plant in Ohio tripped. Lines overloaded as

power moved from further away, voltage dropped, dramatically reducing

the capacity of transmission lines and 50 million people lost power.

A review of electric generation history

For electricity’s first 100 years, the optimal way to produce and deliver power was

with large, remote central stations feeding long wires; this formed a deep, central

generation bias. Initially all power came from two central technologies—hydro and

coal fired steam plants. Hydroelectric plants were inherently remote and early coal

plants were noisy and dirty—not good neighbors. Also coal plants required skilled

operators, making them inappropriate for smaller users. For 80 years, power from

remote plants—linked to the user by an ever-growing set of wires—enjoyed cost adVerDate 11-MAY-2000 22:27 Apr 21, 2004 Jkt 089419 PO 00000 Frm 00052 Fmt 6633 Sfmt 6621 C:\WORKD\ENER03\092503\89419 SCIENCE1 PsN: SCIENCE1
49

vantages over local power. Nuclear power technology, commercialized in the 1960’s,

was also seen as inherently remote by everyone but Admiral Rickover and the U.S.

Navy.

Everyone assumed that central generation was and would always be technically

and economically optimal. Many laws and regulations reinforced this assumption.

If all generation is central, then all power must flow through wires, which seemed

to be a natural monopoly. Laws enshrined a monopoly approach, with good results.

The country was rapidly electrified and power prices feel from $4.00/kWh in 1900

to 5.8 cents/kWh in 1968. The electric age celebrated its 88th birthday. Technology

was changing but local power technologies were blocked.

The monopoly approach created an incredibly strong power industry with deeply

vested interests in all power flowing through their wires, and once central technologies matured, progress stopped. Between 1969 and 1984 power prices rose 65

percent. After 1959, delivered average efficiency never improved beyond 33 percent.

But things changed. People came to hate the ugly fifth column of transmission lines.

We learned more about the bad side effects of burning fossil fuel and as population

grew, electricity demand grew with it. Fossil fuel imports also grew, unbalancing

the budget. Then 9/11 terrorist attacks focused attention on infrastructure vulnerability.

These issues must inform the discussions about preventing blackouts. Fortunately, we have the technology to simultaneously address all problems if we change

the central generation paradigm:

1. Build local power

2. Build smaller

3. Recycle waste energy.

Distributed generation comes of age

Technical progress has provided many local power answers. It employs proven

central generation technologies and fuels but is located next to electric and thermal

loads. DG power goes directly to users, bypassing transmission, and DG plants recycle normally wasted heat, saving fuel and pollution. Local generation options are

technically ripe, environmentally superior, and at least twice as efficient as average

central generation. In fact, much of the technical progress has occurred as a result

of government supported research.

But do not limit focus to sexy new technologies like micro turbines, solar photovoltaic or fuel cells. There are many proven local power technologies, matched to all

medium to large electric loads.

Economics of scale have been reversed by the microcomputer. Small steam turbines, able to extract power from local energy waste were available in 1950 but required operators, making most on-site generation less economic than central power.

Today, microcomputer controls enable steam turbines to operate unattended and

produce economic local power.

Modern gas turbines are clean and compact, unobtrusive neighbors. Two 5MW gas

turbines now generate power at the steam plant serving the White House, the DOE

and the EPA, and they are more than twice as efficient as central plants because

they recycle wasted heat. Their power needs no transmission wires. It stays home.

The most efficient gas turbine yet built is a 50 megawatts LM6000GE, matched

to middle sized industrial complexes or large universities. The next best turbine in

the world is 4 megawatt solar mercury turbine, perfect for hospitals and small industry.

An even better local power opportunity burns no new fuel. The U.S. flares waste

gas, vents waste process heat and fails to harness steam pressure drop that could

support 45 to 90 gigawatts of local, fuel-free, pollution free, wire-free power—over

10 percent of U.S. load. Only 1 to 2 gigawatts of this waste energy is currently recycled. The needed technology is available, proven, and less expensive than central

plants and wires.

The U.S. is out of transmission capacity and electric peak load is projected to grow

by 43 percent over 20 years—300 gigawatts. Line losses have grown from 5 percent

in 1960 to 9 percent in 2002 and exceed 20 percent on peak. If we stay with the

central generation paradigm, we must build 375 GW of large new plants to accommodate peak line loses. By contrast, 300 GW of local power will meet peak load with

no new wires and no added line loses. And, because local plants can recycle waste

heat, we will burn only half the fuel.

The technology is here today but it is the outmoded laws, regulations and the

vested interests in central power that keep deployment at bay.

As I have said, the optimal approach is to:

1. Build local power

50

2. Build smaller

3. Recycle waste energy.

How can Congress find solutions?

This Congress faces a seemingly unpleasant task. The power industry begs help to build more wires—$100 billion of new wires and an improved grid. They ask for

new federal eminent domain rights to enable new wires to slash through forests and

backyards. This will raise prices, annoy voters, and largely fail to address system

vulnerability or to mitigate power system related problems.

There is a better approach:

1. Demand and use the right metric in all discussions. What is the delivered

cost of power? Stop focusing on capital cost and the cost per kWh at the generator—count the line costs and line losses and extra capital for peak loads.

Recognize the locational value of power.

2. Remove regulatory barriers to local power. Instead of new federal eminent

domain for transmission wires, overturn the 50 state bans on private wires.

Give distributed generation operators the right to bypass the wires monopoly

and deliver their power across the street, just as federal laws allow private

gas pipes. Few private pipes are built and few private wires will be built,

but lifting bans on private wires will transform the power industry, ending

the ability of monopolies to block local power with excessive line charges.

Couple this right with standardized interconnection access, the right to

backup power and an environmental regulatory framework that recognizes

the environmental benefits of the combined production of power and heat

(CHP).

3. Encourage and/or demand recycled power development. Pass a clean portfolio

standard that requires a growing percentage of power from renewables and

recycled energy. Give manufacturers a reason to recycle waste fuel, waste

heat and pressure drop.

4. The work of the national laboratories has pushed the frontier of technology

but with efforts often conducted in isolation of broader national needs. There

is a need to assess and refute the still widespread belief that distributed generation can not be safely integrated into the electric distribution system at

reasonable costs. Every effort should be made to showcase and highlight the

many existing commercial technologies that DOE and others have had a role

in developing which can safely and cost effectively integrate DG into the

grid.

This is a short summary of an analysis showing that the optimal way to meet

future electric load growth is with distributed generation—using proven technology

DG. I have attached a more comprehensive analysis in the form of a paper entitled

‘‘Preventing Blackouts.’’

In closing, let me reiterate how to prevent more blackouts while saving money

and reducing pollution:

1. Build local power

2. Build smaller

3. Recycle waste energy.

BIOGRAPHY FOR THOMAS R. CASTEN

Thomas R. Casten has spent over 25 years developing and operating combined

heat and power plants as a way to save money, increase efficiency and lower emissions. A leading advocate of clean and efficient power production, Mr. Casten is the

founding Chairman and CEO of Private Power LLC, an independent power company

in Oak Brook, IL, which focuses on developing power plants that utilize waste heat

and waste fuel. In 1986 he founded Trigen Energy Corporation and served as its

President and CEO until 1999. Trigen’s mission reflects that of its founder: to

produce electricity, heat, and cooling with one-half the fossil fuel and one-half the

pollution of conventional generation.

Mr. Casten has served as President of the International District Energy Association and has received the Norman R. Taylor Award for distinguished achievement

and contributions to the industry. He currently serves on the board of the American

Council for an Energy-Efficient Economy (ACEEE), the board of the Center for Inquiry, and the Fuel Cell Energy Board. He is the Chairman of the World Alliance

for Decentralized Energy (WADE), an alliance of national and regional combined

heat and power associations, wind, photovoltaic and biomass organizations and varVerDate 11-MAY-2000 22:27 Apr 21, 2004 Jkt 089419 PO 00000 Frm 00054 Fmt 6633 Sfmt 6621 C:\WORKD\ENER03\092503\89419 SCIENCE1 PsN: SCIENCE1
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ious foundations and government agencies seeking to mitigate climate change by increasing the fossil efficiency of heat and power generation. Tom’s book, ‘‘Turning Off

The Heat,’’ published by Prometheus Press in 1998, explains how the U.S. can save

money and pollution.

52

New York City, Early Evening, August 14, 2003

On August 14th, around 2:00 PM, a 31-year-old, 650 megawatt Ohio power station

failed. Transmission controllers struggled to route power from remote plants, overloading transmission lines. At 4:06, a 1200-megawatt transmission line melted,

starting a failure cascade. Lacking local generation, system operators could not

maintain voltage and five nuclear plants tripped, forcing power to flow from more

remote plants and overloaded regional lines. By 4:16 PM, the northeastern U.S. and

Ontario, Canada lost power.

This was the eighth major North American outage in seven years, not counting

five localized blackouts in New York City and Chicago. These area wide failures

53

began in 1996 with a blackout of 18 western states, followed by a 1997 ice storm

in Quebec that knocked out much of New England, a 1998 tornado that crippled

midwestern power systems, California system failure in 2000, three ice storms in

Oklahoma and the August 2003 blackout. Pundits spread blame widely and call for

massive investment in wires, while ignoring the fundamental flaw—excessive reliance on central generation of electricity.

Power system problems are deeper than repeated transmission failures. Average

U.S. generating plants are old (average age 35 years), wasteful (33 percent delivered

efficiency) and dirty (50 times the pollution of the best new distributed generation).

Centralized generation, besides requiring ugly, highly visible transmission lines,

does not recycle its own byproduct heat or extract fuel-free power from industrial

waste heat and waste energy. This leaves two starkly contrasting ways to address

blackouts:

• Spend billions on new wires. This will not completely eliminate blackouts and

will exacerbate other problems.

• Save money by encouraging distributed generation. This will greatly reduce

system vulnerability and deliver a host of other benefits.

Distributed generation (DG) has come of age. It employs proven central generation technologies and fuels but is located next to electric and thermal loads. DG

power goes directly to users, bypassing transmission, and DG plants recycle normally wasted heat, saving fuel and pollution. Local generation options are technically ripe, environmentally superior, and at least twice as efficient as average central generation.

Unfortunately, laws and regulations block distributed generation. The industry

and its regulators are caught in an overloaded, wire-entangled web that blocks innovation.

The Wiring of America

Central generation—long considered optimal—is an outgrowth of early generating

technologies. Hydroelectric plants were inherently remote and early coal plants were

noisy and dirty—not good neighbors. And coal plants required skilled operators,

making them inappropriate for smaller users. For 80 years, power from remote

plants—linked to the user by an ever-growing set of wires—enjoyed cost advantages

over local power.

By contrast, transportation required small engines that did not need skilled operators. Coal was tried for automobiles (the Stanley Steamer), but soon displaced by

oil fired piston engines. For the first six decades of the 20th century, power technology evolved along two separate paths—coal fired steam turbines for electricity

and oil fueled piston engines for transportation.

Over time, engine-driven power plants became cheaper to build, but required

more expensive fuel and were only economic for backup or remote electric generation. Coal fired steam power remained a better value for electricity into the 1960

period.

Aircraft needs spurred another power generation technology, the combustion turbine. Pioneered near the end of WWII, early combustion turbines lacked efficiency

but produced more power per pound than engines—critical to aircraft. Technology

marched on. By the early 1980’s, combined cycle gas turbine plants had become

more efficient than the best steam power plants. To fill the gap left by environmental pressure on coal plants, turbine manufacturers developed turbines suitable

for stationary power generation.

54

1Thomas R. Casten and Martin J. Collins, Recycled Energy: An Untapped Resource, April 19,

2002.

By 1980, local gas turbine generation cost less to install and operate, required less

net fuel and produced fewer net emissions that the best possible remote gas turbine

generation and associated wires. Turbines are available from sub-megawatt to two

hundred megawatt, appropriate for local loads; the plants are all automated, clean

and quiet. Generating power locally avoids capital for transmission lines and eliminates transmission losses. Local power plants, unlike remote generation plants, can

recycle byproduct heat, reducing net fuel use and cost. The power industry embraced turbine technology, but clung to central generation, missing opportunities to

save money and pollution with distributed gas turbine generation.

Many other trends of the past thirty years also make distributed generation attractive. Turbine and piston engine power plant electric efficiency continues to increase. Transmission system losses of remotely generated power have increased

from 5 percent to 9 percent, due to congestion. Computer controls enable unattended

local generation based on waste gas and waste fuel. The most efficient generation

technology ever invented, back pressure steam turbines, were historically limited by

operator needs. With computer controls, these devices can economically extract

power from waste heat, waste fuel, and steam pressure drop in virtually every large

commercial and industrial facility. The U.S. currently vents or flares heat, low-grade

byproduct fuel and steam pressure drop that could support 45 to 90 gigawatts of

back pressure turbine generation capacity—6 to 13 percent of current U.S. peak

load.1

Even coal-fired local power now beats the costs of power delivered from remote

coal plants. Advances in fluid bed boilers enable on-site production of heat and

power with coal, biomass and other solid fuels in environmentally friendly plants.

The limestone beds chemically bond with sulfur as calcium sulfate and limit combustion temperatures, reducing NOΧ formation. These clean coal plants, located

near users, recycle heat to achieve 2.5 times the efficiency of remote coal plants.

Given all of these advances, an optimal power system would generate most power

near load, using existing wires to shuttle excess power. Because electricity flows to

the nearest connected users, regardless of the sales contract, locally generated

power bypasses transmission lines.

Which brings us back to those long protected, overburdened, vulnerable, and failing wires that connect remote central plants to customers. Although the power industry finds itself waist deep in the big muddy, it clings to central generation. Every

stakeholder pays. Power prices shot up by 65 percent from 1968 to 84, needless environmental damage continues, many major industry players have declared bankVerDate 11-MAY-2000 22:27 Apr 21, 2004 Jkt 089419 PO 00000 Frm 00058 Fmt 6633 Sfmt 6621 C:\WORKD\ENER03\092503\89419 SCIENCE1 PsN: SCIENCE1
55

ruptcy or are close, banks are saddled with billions of non-performing loans to new

central plants and blackouts have become a way of life.

Regulations and Industry Responses

Competition cleanses, discarding firms that cling to yesterday’s technology. But

the electric industry has long been sheltered from competition. The electric industry’s guiding signals have, since 1900, come from regulation rather than from markets. All ‘‘deregulation’’ to date has left intact universal bans on private electric

wires and many rules that penalize local power generation and protect the incumbent firms from cleansing competition. History sheds light on how and why utilities

and regulators have enshrined central generation and largely continued to oppose

local power generation.

Electricity, commercialized in 1880, is arguably the greatest invention of all time.

But early developers faced a big problem, finding money for wires to transport electricity to users who didn’t think they needed it. To manage the risk, developers

asked city councils for five-year exclusive franchises.

Thousands of small electric companies sprang up; by 1900, there were 130 in Chicago alone. Greedy alderman sold votes to extend franchises. Samuel Insull conceived of (and got) an Illinois state granted monopoly in perpetuity. State monopolies spread.

States established regulatory commissions to approve capital investments and set

rates that assured utilities fair returns on capital. Under rate-based regulation, investments in efficiency improvements increase the rate base, but all savings go to

customers. This approach does not allow utilities to profit from increasing efficiency.

This misalignment of interests eventually caused industry stagnation, but in the

early years, utilities chased efficiency to compete with candles, oil lamps, muscle

power and self-generation.

Banks cheerfully loaned money to monopoly-protected utilities fueling a race to

grow and acquire other systems. Power entrepreneurs borrowed huge sums to gain

control over vast areas of the country. In 1929, the bubble burst; demand for electricity sagged, and over leveraged trusts could not pay debt service. Utility bankruptcies deepened the Great Depression. Congress’s response—the Public Utility

Holding Company Act (PUHCA)—prevented utility amalgamation and assigned federal watchdogs to oversee finances. PUHCA blocked profit growth via acquisition or

financial engineering. Profit-seeking utilities had two options: (1) sell more power

and (2) invest more capital in the rate base.

Both strategies favored central generation over local power. Utilities sponsored research in electric appliances, motors and other novel uses of electricity that increased sales and provided significant public benefits. But they also fought local

generation with every available means.

Electric distribution companies have an understandable bias against generation

that bypasses their wires and cuts potential profits. Utility monopolies long made

it ‘‘Job One’’ to preserve the monopoly. The electric industry sponsored ‘‘Ready Kilowatt’’ campaigns to win industry love and skillfully coached (and paid) governments

at every level to block distributed generation.

For eight decades, central generation was the optimal technology. The regulatory

approach delivered nationwide electrification and real prices fell by 98 percent. Electrification not only improved standard of living, but also played a strong role in positive social change.

Then, beginning in the late 1960’s problems arose. Central generation ceased to

be optimal, but the industry ignored local power innovations. Which brings us back

to stakeholder costs.

56

2Prices given in 1996 dollars as reported at www.eia.doe.gov

The Good Times End

By 1960, as competition withered away, utilities began pursuing questionable

strategies. With no way to recycle byproduct heat, fuel efficiency never moved beyond 33 percent. Utilities and their regulators rushed to convert many coal-fired

power plants to oil, just in time for the OPEC embargo in 1973. Many utilities committed to build massive central plants that required up to ten years to construct,

far beyond safe planning horizons. When rising prices induced conservation, electric

load growth flattened and left the industry with massive overcapacity.

Then came nuclear. The utility industry committed vast sums, underestimating

complexity and safety concerns. Some nukes were built near budget, but others

broke the bank. Cost overruns of 300 percent to 500 percent were common. Long

Island Lighting spent 19 years and $5 billion building Shoreham, only to have New

York Governor Cuomo close the plant before it generated any power.

Figure 1 shows the rising real prices of U.S. electricity after 1968.2 From 1970

to 1984, real electric prices rose 65 percent.

Regulatory responses nearly got it right, flirting with local generation. The 1978

Public Utility Regulatory Policy Act or PURPA sought to improve efficiency by exempting plants that recycled some heat from Federal Power Act regulations and required utilities to buy power from these plants at avoided costs. Utilities fought

PURPA to the Supreme Court, losing in 1984. But subsequent changes removed the

pressure to build plants near users, and nascent DG was again driven back.

Next came Three Mile Island. State commissions, fed up with nuclear cost overruns and rising prices, overturned the tacit regulatory compact. They challenged the

prudence of utility investments in nuclear plants, claiming mismanagement. Historically friendly regulators ordered CEOs to remove billions of dollars from rate base

and reduce electric prices. Utility shareholders took a bath.

The two changes did stop electric price inflation; prices dropped to 1969 levels by

2000. But utility managements went into shock. They curtailed in-system investments, but still needed to put massive cash flow to work. Smarting from independent power producers’ (IPPs) ‘‘poaching’’ of their generation under PURPA, many

utilities funded unregulated subsidiaries to ‘‘poach’’ generation in other territories.

Never questioning the central generation mantra, utility subsidiaries began a disastrous race to build remote gas turbine plants, ignoring this strategy’s vulnerability

to rising gas prices. In thirteen months following May, 2001, the eleven largest merchant power plant builders destroyed over $200 billion of market capitalization.

ENRON, NRG, and PSE&G and Mirant have since declared bankruptcy while,

Dynegy, CMS and Mission struggle to pay creditors. Industry players that embraced

gas-fired remote merchant plant development have seen their credit ratings lowered

57

to junk status. These mistakes have already cost a dozen utility CEOs their jobs,

pounded utility shareholders and caused enormous bank losses.

Major transmission failures did not start immediately. Spare transmission capacity, built in the days of compliant regulation, absorbed load growth until 1996, when

a falling tree set off an 18 state blackout throughout the west. By then, load growth

had made the non-growing T&D system vulnerable to extreme weather (ice storms,

tornadoes, hurricanes and drought induced hydro electric shortages), human error,

and terrorists.

As costs and environmental concerns mounted, States began to experiment with

partial deregulation, but never eased protection of wires, leaving utilities free to

continue fighting DG by charging excessive backup rates and denying access to customers. Commissions allowed generators to sell to retail customers, but then set

postage stamp transmission rates, charging the same to move power across the

street or across Texas. DG power, which only moves across the street, was left to

pay identical transmission rates to power moving hundreds of miles through expensive transmission wires. Wholesale power prices give little recognition to the locational value of generation.

Environmental regulations also suppress distributed generation. The 1976 Clean

Air Act and subsequent amendments penalize efficiency. Almost all emission permits are granted based on fuel input, with no relationship to useful energy output.

All new generation plants are required to install ‘‘best available control technology,’’

while existing plants retain ’grandfather’’ rights to emit at historic levels. These

grandfather rights give economic immortality to old central stations and block innovation, and thus bear some responsibility for system failures.

The costs to all stakeholders from the central generation world view extend to

other societal problems. The balance of payments suffers from needless fuel imports.

The U.S. demands for fossil fuel begat military adventures. Inefficient generation

raises power costs, hurts industrial competitiveness and makes electric generation

the major source of greenhouse gas emissions, threatening entire ecosystems.

An Exception Disproves the Rule

NIPSCO encouraged local power at the steel mills they serve in northern Indiana.

Parent NiSource formed an unregulated subsidiary in 1994 that invested over $300

million in 460 megawatts of distributed power. Primary Energy built five projects

that recycle waste heat and normally flared blast furnace gas. All of the power is

consumed at the steel mills, easing transmission congestion and supporting local

voltage.

The steel mills collectively save over $100 million per year by producing power

with waste energy. These distributed generation projects produce no incremental

emissions and displace the emissions of a medium sized coal fired station, 24/7.

They are the environmental equivalent of roughly 2,500 megawatts of new solar collectors, which would only operate 20 percent of the time, on average.

These projects have not hurt NIPSCO, on balance. Yes, the utility sells less electricity to the mills, but steel production has risen, requiring more shifts and pumping up the local economy, increasing other electric sales. There is no reason why

similar projects cannot be built to the benefit of all stakeholders in every other electric territory.

58

Whether ’tis Nobler to Spend or to Save; That is the Question

There are two distinct paths to avoid blackouts. Spend $50 to $100 billion on new

and upgraded transmission lines or save money by removing barriers to distributed

generation.

The first path will raise electric rates by 10 to 15 percent and will exacerbate

other problems. The second path will cost taxpayers nothing and mitigate other

problems.

To follow the second path, governments must:

• Allow anyone to sell backup power

• Enact standard and fair interconnect rules

• Void laws that ban third parties from selling power to their hosts.

• Give every power plant identical emission allowances per unit of useful energy.

• Recognize the locational value of generation.

• Most importantly, allow private wires to be built across public streets.

These changes will transform the $390 billion U.S. heat and power business into

a dynamic marketplace of competing technologies and allow distributed generation’s

competitive advantages to prevail. Utilities and IPPs will build new DG capacity to

serve expected electric load growth and reduce transmission congestion.

Ending central generation bias will upset vested interests and require a great

deal of political effort, but the rewards for this leadership will be immense—lower

power prices, reduced pollution, reduced greenhouse gas emissions, and a vastly less

vulnerable national power system.

Thomas R. Casten has spent 25 years developing decentralized heat and power

as founding President and CEO of Trigen Energy Corporation and its predecessors

and currently as founding Chairman and CEO of Private Power LLC, an Illinois

based firm specializing in recycling energy. Tom currently serves are Chairman of

the World Alliance for Decentralized Energy (WADE), an alliance of national and

regional combined heat and power associations, wind, photovoltaic and biomass organizations and various foundations and government agencies seeking to mitigate

climate change by increasing the fossil efficiency of heat and power generation.

Tom’s book, ‘‘Turning Off the Heat,’’ published by Prometheus Press in 1998, explains how the U.S. can save money and pollution.

The author can be reached at: Private Power LLC, 2000 York Rd., Suite 129, Oak

Brook, IL 60523; Phone: 630–371–0505; Fax: 630–371–0673; E-mail:

tcasten@privatepower.net

59

DISCUSSION

Chairwoman BIGGERT. Thank you very much.

At this point, we will open our first round of questions. And the

Chair recognizes herself for five minutes.

Mr. Glotfelty, your office is charged with improving the reliability

of the electric system. And Dr. Smith has argued that the best way

to encourage innovation and investment is to have a fully competitive market. Is there a conflict between innovation and reliability

and between competition and reliability? And are you concerned

that as we move toward a completely competitive market that

there will be increased pressure to push the system beyond its limits? And then Mr. Casten suggests that there should be a—it

would—it should be local and we should use waste energy. Has—

is your committee looking—or commission looking into this, also?

Mr. GLOTFELTY. To address Dr. Smith’s concern, we absolutely

agree that demand response is a critical component to ensuring future reliability as is distributed resources. They are one of the components in a wide array of choices that we have to implement. I

don’t believe either one of them are the silver bullet to ensuring

greater reliability or a greater and more efficient transmission system or electrical system, generally speaking, but they are two of

the most critical components as we move forward that have to be

addressed.

The problem, from our standpoint, is both of those issues are

State issues. They deal with retail customers. At the federal level,

we deal at the wholesale level. So there has been a conflict for

many years that the Congress has grappled with when considering

energy legislation as to do you violate the States’ rights that deal

with the retail customer and say demand response is a federal

issue and therefore we promulgate these rules. And the same thing

with distributed resources. It is a conflict that I think is apparent

in the energy bill that is being considered today, but it can be resolved. And it should be resolved, because both provide a valuable

component for a more efficient and reliable transmission system.

Chairwoman BIGGERT. As far as the recycling of waste energy, is

this a possibility?

Mr. GLOTFELTY. Absolutely. Combined heat and power, in this

Administration, going as far back as the President’s National Energy Policy, we have said time and time again that we are believers

in that. Combined heat and power is very efficient. It is good for

the environment. In my past life, I worked for a company that

owned about 20 co-generation plants. They are very good for the

environment, and they are very good for the system. Again, you get

into the—and those were large plants. But as you get into smaller

combined heat and power plants, the majority of the rules that are

prohibiting their application into the system are at the State level.

They are not at the federal level. I think this—FERC has tried to

implement standard interconnection agreements, and they do affect

large generation that is tied into the transmission system, not

that—at the distribution level that is under State regulation.

Chairwoman BIGGERT. Thank you.

Mr. Casten, you talked about some of the—where your company—at the steel mills, et cetera, but could you just kind of deVerDate 11-MAY-2000 22:27 Apr 21, 2004 Jkt 089419 PO 00000 Frm 00063 Fmt 6633 Sfmt 6601 C:\WORKD\ENER03\092503\89419 SCIENCE1 PsN: SCIENCE1
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scribe the products or services and then what benefits do your

products—projects offer to both your company and to your customers?

Mr. CASTEN. Every steel mill puts coke and iron ore in a big

blast furnace and makes iron out of it. It emits a very dirty, lowenergy gas. EPA requires that gas to be flared to clean up some

of the pollutants in it. Three of our projects put in a special boiler,

burn that gas, cleaning up the pollution, and then just recycle the

energy and turn it into electricity and steam, all of which goes to

the steel mill, cuts down their purchase of outside power and cuts

down their pollution, et cetera. There are comparable projects with

most chemical factories, refineries, other places with the same type

of thing. So they benefit from lower prices, the grid benefits from

less demand on the system.

Chairwoman BIGGERT. Is this something like methane gas from

landfills or anything that could be used?

Mr. CASTEN. Methane gas from landfills is a great example of recycling. It can use some other technologies, because it is about half

as energy intensive as natural gas. The stuff we are burning is

eight percent of the energy of natural gas, so there are a variety

of technologies to get the different waste heat, but yes, many

things can be done.

Chairwoman BIGGERT. Thank you.

My time is up, so I will recognize Mr. Lampson for five minutes.

Mr. LAMPSON. Thank you. Madame Chair.

Let me start by asking Mr. Glotfelty and Mr. Glauthier a comment on Mr. Casten’s testimony. What are your feelings and maybe

concerns? It doesn’t matter whoever wants to start.

Mr. GLOTFELTY. I believe he is on target. I mean, he—again, he

has addressed one of the issues that needs to be addressed in order

for us to get a more efficient and reliable system. It—I think from

my standpoint, if we got, even in our wildest dream, 20 or 30 percent integration of distributed resources in our system, in a decade,

that would still mean that 700,000 megawatts would still have to

travel over our transmission system. So we can’t neglect the transmission and distribution system and put all of our eggs in the distributed resources basket, because it will not supply all of our

needs in real time. But it is a critical component that can help us

over the next decade achieve a more reliable and efficient system.

Mr. GLAUTHIER. And I agree with that. I think we need to go

even further than Mr. Casten did. We really need to think about

distributed energy resources that include photovoltaics and other

renewables, ultimately fuel cells in widespread use. The system

that will support that needs to be modernized. The distribution system, as well as the transmission system, needs to be upgraded to

a point where it can incorporate that kind of equipment and support it effectively. We need to be able to make that kind of distributed energy, literally point and play. So you know, as you bring

home a new printer for your computer, you plug it in, and the system recognizes that and initializes and it can incorporate that.

Today, that is not the case for electricity. Every new application is

a custom connection. We need to make that sort of technology improvement. And that is part of the modernization that we are supporting that I think the Department of Energy can lead and the

61

Congress can help to provide the kind of direction and support for

it that we think is important.

Mr. LAMPSON. Mr. Glauthier, you have seen the New York Times

article from Tuesday this week regarding reactive power?

Mr. GLAUTHIER. Yes, I have.

Mr. LAMPSON. Can you tell me a little bit about reactive power

first? And then has EPRI done a study relative to reactive power

and the August 14 blackout?

Mr. GLAUTHIER. EPRI has conducted some analysis of working

with First Energy and with the data there and has submitted that

to the Department of Energy to the—for the use of the task force,

that is the international task force. And we expect that that will

be some of the information that they will be able to put together

to come up with a final answer on what had happened.

The reactive power itself is something I can give you a brief explanation, but I am not an electrical engineer. And I do have with

me, as I mentioned earlier, Dr. Sobajic from EPRI, who could give

you more in detail if you would like to have that.

Mr. LAMPSON. Just a simple, if you can.

Mr. GLAUTHIER. Reactive power is necessary to be able to allow

the regular power to flow through the lines. And there has to be

enough of this balance, if you will, to allow the whole system to operate. So if you have plants that are operating and just providing

their power into the system and not reactive power, they—those

have to draw reactive power from somewhere else. It is a necessary

balance in the system. And that is something that utilities in the

past were, I think, more able to provide because the whole systems

were integrated. As we restructure the system and we have independent entities performing the different functions, that becomes

more complicated. It requires more coordination and more coordinated management.

Mr. LAMPSON. We may explore that more in time. Is it possible

that this committee can have a copy of that study? Could you get

it to us?

Mr. GLAUTHIER. At this point, we would be willing to submit it

to you, but it is really a restricted report, because we are trying

to provide it to the task force for its use, and we envision making

it public later on as part of the data that, I think, everyone will

have access to eventually. So we would ask that you would respect

that, if you would, and on that kind of a basis, we would be willing

to do that.

Mr. LAMPSON. Okay. We would like that when it is possible.

Let me—my time is running very short now, and this is sort of

an open-ended question that I have, and I want everyone to respond to. Perhaps we can start it and then on the second time

around, we will continue what I am doing. But I thought it would

be interesting to hear your comments, all of you, about the top

three technologies that are already developed and need to be deployed in order to increase the reliability and efficiency of the bulk

power transmission system and perhaps the top three technologies

that need to be developed for further—to further increase the efficiency and reliability.

62

And the red light came on, so that is my question. When we come

back around the second time around, that is what I would like for

you to begin with.

Chairwoman BIGGERT. Thank you, Mr. Lampson.

The Chair recognizes Dr. Ehlers for five minutes.

Mr. EHLERS. Thank you, Madame Chair.

I—first of all, I just want to commend Mr. Casten for what he

is doing. This is something that is badly needed, and we really

have to expand it across the country. This is something we have

known about for years and just never get behind it and push it, because everyone likes to think of grand projects rather than small

projects. I was not aware of any discrimination by the State public

utility commissions on this. I thought they were all adapting to it.

If that is a problem, that is something we can try to address.

Mr. Glauthier, I really appreciate your comments about a smart

grid. Something that really has irritated me since the blackout is

the repetitive theme I heard initially on the news media that the

grid is so complicated, no one can really understand it. And that

is one of the most absurd statements I have heard, because there

are far more complicated systems that we deal with in this world

than the grid. And clearly, we know how to do it. We can understand it. And we have to do what you said, build a smart grid that

incorporates our knowledge of today into a system that is a little

bit, perhaps, archaic.

Having said that, I do want to pursue the reactive power, since

you said you brought an engineer around. And I don’t know how

many of you are engineers. But I would like to hear the explanation. Is it just caused by the phase difference between the—or

is this something different?

Mr. GLAUTHIER. With your permission, I would be happy to introduce Dr. Sobajic. Would you——

Mr. EHLERS. Okay.

Dr. SOBAJIC. Well, I will try to do this simply, although—I am

Dan Sobajic. I am working for EPRI. I am Director of Grid Reliability and Power Markets. And this is a subject that has been

brought up in many occasions like this one, you know. And sometimes we engineers, you know, have a difficulty explaining. We go

through analogies to make people understand it.

Mr. EHLERS. Well, we have two physicists here, myself and a

staff member—no, three now.

Dr. SOBAJIC. Well, you are——

Chairwoman BIGGERT. This is beyond some of our pay grade,

however.

Mr. EHLERS. So you can get technical for us, and——

Dr. SOBAJIC. Well, let me put it this way. T.J. just mentioned

that if you deal with the ultimate in current, as we are dealing

mostly in our grid, the power that flows is not active or reactive.

There is just the plain power. And this is what you have down the

lines. And power is the contract. It is what mathematically becomes the product of the voltage and current and if you like to go

deeper in the electricity. However, these systems, when analyzed,

and this is what we have to do in order to understand them very

well, leads to some representations that involve complex numbers,

if you like mathematics. Okay. And these numbers have a so-called

63

real and imaginary part. Now you, perhaps, remember that. This

is what we call active power or the part that is the real part or

it is active. And the other one is so-called reactive. Okay. It doesn’t

mean that it is imaginary. Again, this is what mathematicians like

to call it. But this is—these are the components of that phenomenon. And then you can go further on and analyze what are

the effects of these two components when you break it up. And you

can see that both of them are needed. You know. Active power, as

we all know, does the work, and reactive power is very important

to allow active power to do the work. So it is—it leads to an analogy that someone said it is about a car. You know, you need the

gas to drive it, but you need the oil in order to be able to start the

car and move. It is not quite there, but this is sort of coming to

what it is.

So basically to put it, the bottom line is that you need to respect

the need for the active power in order to be—to have an efficient

functioning system. And I think I should stop there, because the

rest goes into the market rules and why don’t we have it and so

on and so forth.

Mr. EHLERS. My question is are power companies deliberately ignoring this in order to push more real power out and therefore connect—collect more money without taking care of the complex variables involved? Say hey, there is a limit to what you can do here.

Dr. SOBAJIC. I think what one can see is that the way how the

market system has been set up, it is clearly promoting delivery of

the active power. The reactive power is, as we call it, an auxiliary

service, which is already—which is the word auxiliary. It means,

you know, something, perhaps, outside or—that is definitely needed, but——

Mr. EHLERS. But does a power generator make more money by

ignoring the ancillary?

Dr. SOBAJIC. Well, I think the auxiliary services are also recognized in the market model and provided for. Whether there is a

balance in how these services are both recognized in terms of the

market rules, that is a different question, but clearly there is a financial incentive whether to do the active or not. Thank you.

Mr. EHLERS. Okay. That is what I was trying to get, whether it

is a physical problem or a financial problem.

Dr. SOBAJIC. No, it is not a physical problem.

Mr. EHLERS. Okay. Yeah.

Dr. SOBAJIC. I think systems are quite capable of——

Mr. EHLERS. Okay. So it is a financial issue and therefore it

should be subject to regulation?

Dr. SOBAJIC. Possibly.

Mr. EHLERS. All right. All right. If Mr. Smith wants——

Dr. SMITH. Sir, may I speak just briefly to this point? Think of

reactive power as being associated with voltage and frequency control. If you don’t provide it at the end of a long line, a long transmission line, it very much limits the capacity of real power that

you can get through that line. It is possible, entirely possible that

if—that someone might gain by limiting the transmission throughput by providing inadequate reactive power to compensate for the

absorption in that long line. But this is—I think it is—why it is important ultimately that reactive power as well as real power be

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priced out node by node, and I think we—and I think that technology is going to allow us to do that in real time. And we are moving in that direction. I have worked with the Australians, and they

are right now particularly—very much interested in pricing—developing pricing systems for reactive power in the grid.

Mr. EHLERS. And I might just observe there was a similar problem years and years ago when two electrical plants first interconnected, because they would play games having a phase lag and

trying to gain financial advantage that way.

Dr. SMITH. Yes. Yes. That is entirely possible. That is the reason

why you want to pay people for producing reactive power.

Mr. EHLERS. Thank you very much.

Chairwoman BIGGERT. Thank you, Dr. Ehlers.

The gentleman from California, Mr. Honda.

Mr. HONDA. Thank you. Madame Chair.

I find this discussion pretty interesting and for a novice, I think

some of the lines are becoming pretty clear. What I hear folks saying is that there is a distinction in terms of policy arenas that one

is federal and other state. And so it sounds like that there could

be some artificial barriers just because of that. And what I hear

other folks say is that if you are thinking about the consumer, and

it seems to me if you look backwards in terms of policy making,

then it would be—creates a different paradigm of the areas of responsibility. And it seems like if we go from the consumer backwards to create a policy for energy, it might make more sense than

solving some of the problems in terms of barriers. Because what I

have learned about our problems is that the grid and the transmission and the generation of electricity and the consumption is

not state. It is regional. And so, you know, it seems like there are

some archaic paradigms that we are forced to work under.

I guess my question is are there different ways of looking at policy development rather than separation of federal and State and

looking at the consumer and developing policies that way. And I

think I agree that we have to have a smart grid, you know, for us

to have at this period of generation of energy so that the consumer

ultimately ends up being the winner. What would be your comments to the observation I am trying to make and trying to understand, wrap my arms around?

Mr. CASTEN. May I answer?

The policy all stems from the fact that the paradigm is that all

power flows through their wires. They are a natural monopoly. We

have to protect the monopoly, and so we have set up a very powerful set of vested interests to make sure that all power ever used

will flow through those wires. And the regulators see it as their job

to protect that. As a consequence, we don’t look at it from the consumer point of view and say what would we do in an optimal situation without this. The example just discussed is classic. In all of

the power plants we have ever built, we have often been required

to support the voltage at the back end, to change our power factor

to help out the grid. We have never been paid for it. It is a value

that you need, that the consumer needs, but the system doesn’t

want distributed generation. And consequently, we don’t do the

right things. We really have to fundamentally go back to saying no

more monopoly on wires, and then it will start to unfold itself.

65

Mr. HONDA. Thank you.

Dr. SMITH. Let me say that I think here is the problem. Every

customer is charged for this cost for the wires and all of these capital investments. It is determined by peak demand, not average demand. A customer who is served by energy sources closer to him,

which is what Mr. Casten is talking about, shouldn’t have to pay

the full price for the capital costs. He is not using it, or he is only

using it for backup or something like that. And he should have substantial savings from that. And until you have that kind of a system, you are not going to have the ordinary innovations that occur

in response to the people’s attempt to profit by doing things better.

You just simply don’t have maximum opportunity for that development to occur. So when you compare the electric power industry

with industries that—telecommunications and computers and everything, you see an industry which is not nearly as flexible and

not as prone to innovate. And we are talking about innovating in

the interests of the customer: saving him money and giving him

better service.

Mr. GLAUTHIER. I think your observations are very interesting in

that there are many states and Federal Government are trying to

find ways to spur this kind of innovation and flexibility for customers. Many of the states are going through restructuring or trying to find ways to do that that allows the innovation but also protects the customers. This is one area where the commodity we are

dealing with is an essential requirement for everyone. Electricity

underpins our whole way of life, so it is not an optional item but

rather one that they need to be sure there is an adequate protection. And there also are generally going to be connections into the

grid. We are not talking about applications where people are going

to generally go off the grid and be totally independent, so you need

these things to be interconnected and to be integrated.

I think what we need is also the technology development that

will support this. Right now, the communications system and the

power system are not integrated, so in order to do the real time

pricing that Dr. Smith talked about or to provide the real dogmatic

load management systems, you need communication to the customer site, so the customer systems recognize when there is a peak

in the demand and they ought to scale back their own use or at

what points they really change their generation and perhaps generate power into the grid. But I think these two go together; the

regulatory questions and the technology development are both important.

Mr. GLOTFELTY. Very quickly, I would agree with most everything that was said but go back to the jurisdictional issue, which

I think is the biggest problem. The interaction with the retail consumer is governed by the state, which means we have 50 different

State rules on how we get distributed resources or demand side

management or control technologies onto the grid to allow more

consumer interaction. And that is a tough issue to crack, considering that retail consumption of electricity is not an interstate commerce, as is the wholesale market. It is something that I think

Congress is trying to address. But in the meantime, the Department of Energy, as well as many associations and groups, have

been working with the states to try and get model interconnect

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agreements and model policies that can be adopted at the State

level to increase the deployment of these technologies. However, it

is not as quick as it could be. But it is a challenge, and it is moving

down the road.

Mr. HONDA. Thank you, Madame Chairman. Just a real quick

comment. I think if the consumers got more educated, there would

be some changes.

Chairwoman BIGGERT. Thank you, Mr. Honda.

We do have a vote coming up, but we have got time for another

round of questioning from Dr. Gingrey.

Dr. GINGREY. Thank you. Madame Chairman. I will make this

brief, because I know we do have to go vote.

Excuse me. Mr. Glotfelty, the National Grid Study, which led to

the creation of your office, called for the elimination of transmission bottlenecks, can demand response technologies and distributed generation technologies help eliminate the bottlenecks and the

grid congestion generally? And if so, how would we best encourage

these technologies?

Mr. GLOTFELTY. The answer is a resounding yes. There are models out there for demand side management that today decrease bottlenecks. A great example of that is in southwestern Connecticut.

They have had a very hard time building additional transmission

lines. With the implement of a market in the Northeast, prices this

past summer were going very high. A new demand side management program that the Department helped support but was supported by the utilities as well as the state, allowed a tremendous

demand response, which reduces—reduced prices for not only the

consumer but for the whole region. There is a great example, and

it is a great model that can be replicated across the country.

For distributed resources, I think there are a lot of models from

the—in the Southeast to California. Other states have good models

for putting additional distributed resources on the grid. I think,

again, we go back to this State issue. Each State is different and

each region is different, so the model is going to have to fit each

region.

Dr. GINGREY. And let me ask both you and Mr. Glauthier. Some

have suggested that much of our transmission and distributive congestion could be relieved by simply replacing the basic 1950’s era

grid technologies, such as the wires, the transformers, and the mechanical switches with today’s state-of-the-art technology. For example, we have heard of wires, and I think you mentioned this earlier, that carry three to five times more power or digital switches

that improve the capacity of the grid. How much would this help

compared with the technologies you have proposed and that others

have mentioned? And how would its costs compare with some of

these alternatives that we have already discussed this morning?

Mr. GLAUTHIER. Thank you.

I think those are very important, and I think they are all part

of the overall solution, that there is not any one solution that will

take care of this. The transmission lines, or conductors as you

talked about, are under testing by the Department of Energy and

by EPRI and others. And there are at least five or six different

manufacturers of that. So there is the opportunity for some competition among those. And they are quite cost-effective, if they

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prove out. Right now they are in the testing phase to be able to

be certified for use in commercial applications. So our hope is that

those will be ready soon, perhaps in the next year or 2 years that

those can begin to be used.

Other digital controls also can be installed, but in some cases,

the cost needs to come down. There are the FACTS devices, the

Flexible AC Transmission Systems I described. There are only nine

or ten of those installed in the country right now because they cost

several million dollars a piece, in some cases $10 million or more.

But those are solid State controls that can actually direct the

power flow and can eliminate loop flow problems and other difficulties. That is the kind of thing. We need to spur the development

of a family of those controls that can be scaleable down to smaller

sizes and be cheaper and be installed in numerous locations

throughout the whole grid.

Dr. GINGREY. Thank you. And thank you, Madame Chairman.

That concludes my questioning.

Chairwoman BIGGERT. Thank you, Dr. Gingrey. As you heard

from the buzzers, and if you heard the beepers that—we do have

a vote on the House Floor, so we will—it is just one vote, so it

should not take us too long. So we will stand in recess to the call

of the Chair.

[Recess.]

Chairwoman BIGGERT. If we could resume, the witnesses will

then take their seats. All right. We will call the Committee to order

again. As long as some of our Members have not returned, I think

that we could give five minutes to Mr. Lampson on the question

that he asked earlier.

Mr. LAMPSON. Thank you very much. I might as well start.

I had already posed the question to you, and so if each of you

would talk about the technologies that exist and we need to implement and those that we might need to try to develop over time.

Right. From the left to the right. All right.

Mr. GLOTFELTY. From our perspective, I think the technologies

that are here today that just need to be deployed onto the grid are:

higher capacity transmission lines; wide area measurement systems, which measure the state of the grid, voltage, all sorts of components of the grid in a wide area, we have it in the West, we do

not have it in the East; and training for our operators to use this

new technology that is coming. It is critical that they have an understanding of how new power electronics and new technologies can

help them make the system more reliable.

I think in the future it is high temperature superconductivity

and the wide variety of technologies that come from that, whether

they be cables, fault current limiters, or other technologies that

really have no losses. It is storage and it is power electronics. Storage has the ability to help peak shave. It has the ability to help

provide backup for entities that—like batteries. There are new

technologies coming down the road that can help entities be more

efficient as well as firm up their reliability for their industrial processes. And power electronics, of course, is something that we are

working on with EPRI as well as the industry on how we make

sure that the grid is controllable, how we can isolate problems

without them becoming widespread where we can really ensure

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that the grid is reliable in the future. It is a few years off, but we

are working on it today.

Mr. GLAUTHIER. Thank you.

I add to that list a couple of things that are here now. The State

estimators is a software term that—systems that can calculate

within seconds, the PJM system about every 30 seconds calculates

the state of the system from all of the data coming in exactly what

is happening. The State estimators are not being widely used in

most of the systems around the country. The systems need more

sophisticated work so that the operators will really feel that their

information coming out of them is reliable. That is an area that is

here. It can be done now. It is—needs to be improved so that operators have the best information possible as they are running the system.

Along with that is wide area data to the operators so they can

see what is happening in neighboring control regions. They have

the data on their own control region but they have no idea exactly

what is going on in the areas around them. It is very helpful, and

it is possible with today’s technologies. In fact, it has been demonstrated in some applications that DOE has done and that we

have done how to do this and how to make that data available on

a real time basis.

Mr. LAMPSON. Are either of those extremely expensive to implement?

Mr. GLAUTHIER. No, they are not. They are——

Mr. LAMPSON. Well, why aren’t we already talking about doing

it then? Why——

Mr. GLAUTHIER. Part of it has to do with access to the data. It

is providing data to your neighbors, you know, your own operations. There is some extra software development and some costs

involved, so it just hasn’t been high on the list, but it is something

that I think we need to make a greater priority. And now that outage in August will perhaps give more visibility to that sort of thing.

It has just not been viewed as one of the top priorities.

I would echo what Mr. Glotfelty said about the transmissions

lines, the new conductors that will be able to carry a greater

amount of throughput so you could re-conductor some existing

transmission corridors and get more power through those without

having to build or permit new transmission corridors and the like.

On the existing technologies, I would also say real time sensors.

We have sensors in all sorts of applications now in other sectors.

We are a wireless society and becoming a wireless society, but the

electricity sector is not—has not caught up. The electricity sector

is not as widely computerized and is not using the real time information that it could. Mr. Glotfelty mentioned the wide area monitors or sensors in the West. We ought to have them throughout

the whole system and it—and all sorts of equipment. Ultimately,

every piece of equipment is going to be sending in information

about how I am doing and what is happening.

In terms of new technologies, the power electronics area is really

important. I mentioned the FACTS systems earlier that can actually control the power flowing through an area of connection. And

right now, the wires are just a set of dumb wires. The wires are

out there, and you put power into one place and it will flow

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through the system. But we need real controllers out there. And we

can do that, but they are expensive. We need to develop a more

cost-effective set of those, a scaleable set that will be able to be

used widely throughout the system.

Just two other quick things. The technology to get the distributed energy resources, the kinds of things that Mr. Casten has

talked about and in addition solar powered and many other kinds

of renewable power, to be able to be plug and play. That is actually

something that can be done. We are working on it with the manufacturers and vendors. The Department of Energy is working on it.

It is not something that is going to take a long time, but it has to

be done in a way that provides the standardized protocol, the

standardized methods so that these can be widely used.

Mr. LAMPSON. Madame Chair do you want to let—just let them—

we still don’t have anyone else to—or do you have a question that

you want to go on a different direction on and we will come back

to the last two on?

Chairwoman BIGGERT. No.

Mr. LAMPSON. Okay. Then——

Chairwoman BIGGERT. Proceed, Dr. Smith.

Dr. SMITH. I think the problem is to have—try to get in place incentives that enable people to put their own money up, incur the

cost of investing in some of these new technologies and getting the

benefit from it. Now what is hard, of course, is that those benefits

are widely distributed in the system. And the problem—and the

grid. And the problem is to figure out how those savings can—the

individual who incurs the investment can, because of the savings

he is enabling the system to enjoy, to capture revenues in response

to his—to the investment costs that he incurs.

Now I would ask—would like to ask Mr. Glauthier if he sees—

if he is at all hopeful that the control system could enable you to

also compute benefits and savings and come up with a way of pricing this so that the individual who invests in it can benefit.

Mr. GLAUTHIER. I think the answer is yes, if I may.

Mr. LAMPSON. Please. Go ahead.

Mr. GLAUTHIER. Really having the access to the data and having

a set of information coming in through—from throughout the system on a real time basis does give you the power then to construct

different kinds of pricing systems, to administer them, to make the

whole system a richer and more robust way of managing.

Dr. SMITH. That is all I have.

Mr. LAMPSON. Okay. Mr. Casten, do you want to tell me about

those technologies?

Mr. CASTEN. Thank you.

The three most important, hands down, the microprocessor. Old

power plants required six to eight attendants per shift. And when

you double up all of that labor, you just can’t make a small power

plant economic. The microprocessor lets us operate any kind of

technology unattended. And it just takes the scale out of—one of

its advantages. Another advantage is that we do connect up in real

time to all of our customers’ meters. And once we have got a customer, we do what we say the—what Dr. Smith says the grid ought

to do. We are monitoring and actually causing them to drop their

peak loads to make better use. That is one.

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Number two is the advances in gas turbine efficiency. When I entered this business 25 years ago, the best gas turbine was 22 percent efficient, and the best thermal plant was about 33 percent efficient. Today, the best thermal plant is still 33 delivered. The best

gas turbine is about 42. You can combine the cycle and get it up

to 55. The best news is that if you take the two most efficient gas

turbines in the world today, one of them made by Solar is four

megawatts, about the load on the Hinsdale Hospital. So there is no

reason why you can’t put these things out. In fact, it makes no

sense to burn gas anywhere but locally, thanks to that and the

third technology.

The pollution control is astonishing what has happened at the

source. The best turbine available 25 years ago was about 200

parts per million of NOΧ, which is roughly comparable to what you

get out of a big thermal plant. The best ones today are two parts

per million. So we formed this whole paradigm that the power

plants had to be located a long ways away, because they had to be

located a long ways away. They were ugly and dirty and needed

a lot of people. Today, they are inconspicuous. There could be one

in the basement of this building, and you would never know it.

With respect to the second part of your question, what technology

is needed, I can offer only two. One I wholly support Dr. Smith’s

idea of getting to the point where there is a signal on the wire telling every consumer the marginal cost of power at that moment so

that smart appliances could pick it up and decide whether to wash

my dishes right now or wait until three in the morning. The other

thing I think the Committee could look at is some work on technologies that we cover energy from lower quality heat. That is a

field that hasn’t been investigated very much. There are some

promising ways to use even lower temperature heat and convert it

to electricity, and that needs some science, some fundamental

science.

Thank you.

Mr. LAMPSON. Thank you all very much, and I yield back.

Chairwoman BIGGERT. Thank you. Then I will continue with the

questioning.

Mr. Glauthier, many have said, and I think that you agree, that

we have under-invested in the grid. And I wonder if you have some

indicators of this under-investment. But I also want to go a little

bit further than that, because we are talking about a grid, and we

have heard a lot—most of you had mentioned at some time we run

into State laws and that—and another factor has been that because

of the deregulation that this has had a—has been a factor in the

blackouts that we have incurred. So is there—do we have a choice

of whether we are going to really improve the grid? Should we have

a national policy so that we can, you know, avoid the State laws

and, for example, then Mr. Casten would be, perhaps able to cross

the street with his—with private lines? It seems like we have got

an awful lot of factors here with the regulation that is causing part

of the problem. And maybe start with you, Mr. Glauthier.

Mr. GLAUTHIER. Yes. Thank you.

Investment has been lagging in the grid, the distribution and

transmission parts of the system, and especially the transmission

part, for the last decade. Part of it is due to the confusion that

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there has been about what the regulatory structure and the ownership responsibilities will be for the transmission system. There are

changes that the Federal Energy Regulatory Commission has proposed, changes that individual states have put forward. And many

cases, the owners and potential investors in the grid just need the

rules clarified. They could——

Chairwoman BIGGERT. And I believe that that is also in the National Energy Bill that we have right now that is in conference.

Mr. GLAUTHIER. It is. And it is part of the energy proposals by

this Administration and the previous Administration to try to make

those decisions. So that will help. And there is, I think, a question

about the returns. There is a lot of discussion about what rate of

return is sufficient to bring about that kind of investment. The

question really needs to be focused on what is the realized rate of

return. It is one thing to have an allowed rate of return, but if, because of rate freezes or because of other delays or other things,

they are—companies are not able to realize the returns that are allowed, that is an issue. So I would suggest that people need to look

at the reality of what returns actually will come.

Chairwoman BIGGERT. Okay. Do you have any figures on that

that you would——

Mr. GLAUTHIER. Well, the investment right now in the trans- mission system and the grid is about $3 billion a year. And the estimates that the Electric Institute has used is that they think it

ought to go up to about $5 billion a year to—really to maintain the

current system. And our feeling, as I said earlier, is that we think

the investment needs to be about $10 billion a year in order to

modernize the system so that you are not just fixing the current

system but you are also moving ahead to really add the computerization, the sensors, the real time controls that are needed to

make this system operate in both the reliable and secure fashions

we described and to enable the kinds of applications that will really

make it possible to use it so that customers can control their loads

better and you can get more distributed energy and other things

connected.

Chairwoman BIGGERT. Well, given the cost of transmission improvements then tenths of a cent per kilo-hour and the benefits to

customers that you describe, which are orders of magnitude higher?

Should the rate payers bear this cost?

Mr. GLAUTHIER. Rate payers probably will, and it is not a huge

cost. The total of all electricity revenues right now in the country

is about $250 billion a year. So if you add $10 billion a year to that,

that is a four percent increase. But the key is that this needs to

be an incremental investment. The utilities already are spending

the money to try to keep their current systems running and to keep

the lights on for everybody. They are operating under regulatory

controls at the states where people are trying to keep the customers—give the customers the lowest rates possible. Everyone

needs to realize that this is an investment in the future and it will

provide a lot of benefits.

As Dr. Smith said earlier, the benefits are widely dispersed, and

so it is harder to identify exactly who gets those benefits. But there

are real benefits there. Our estimate is that the cost of power disturbances right now is about $100 billion a year, year in and year

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out. And that is not the cost of the August outage. That is just the

regular disturbances, not always blackouts, but often the fluctuations that are enough to make a chip producer go off line or to

make a pharmaceutical batch that has been going for 10 days unusable, things of that sort.

Chairwoman BIGGERT. And would special financing be required?

Mr. GLAUTHIER. What our recommendation is that the Department of Energy be instructed to look into this and work with the

customers. Work with the State regulatory commissions, work with

the industry and other stakeholders, and come back in a year with

the recommendation. We think that there may be mechanisms that

would provide incentives for this investment or other ways, perhaps working with the National Association of Regulatory Utility

Commissioners to have the states, as a group, embrace some approach to going ahead. Ultimately, the customers probably pay all

of this cost, but if there is a concerted effort to do it and a commitment to really move ahead and invest something in the system,

that is what is going to make it happen. A business-as-usual approach is probably going to take a long time and just, you know,

be very, very slow.

Chairwoman BIGGERT. Would anybody else like to speak either

to the under-investment or to the national policy or—Mr. Casten?

Mr. CASTEN. The slight problem with the investment is that the

industry knows how vulnerable it is to continuing the present

model. And if the industry doesn’t know, the banks do. And so

there is a growing reluctance to put a lot more money into wires,

which are probably obsolete before you ever build them.

And my second comment is that I don’t know how any of this

mess gets straightened out until Congress asserts that electricity

is, indeed, interstate commerce, because you have heard that all

day. And it is just really a problem with all of the states asserting

jurisdiction.

Chairwoman BIGGERT. Anyone else?

Dr. Smith.

Dr. SMITH. I think the real problem is not so much under-investment but the direction of investment. You see, we have these technologies that can improve the grid and make it more efficient. We

also have technologies that completely bypass the grid that Mr.

Casten was talking about. And I have a question I want to raise.

Suppose that I own a high-rise apartment, in particular this is for

Mr. Casten, but for anyone else. Suppose I own a high-rise apartment house, and I want to buy one of those four-megawatt units

to supply my own power needs, and any excess capacity, I want to

dispatch it out to the rest of the world through the local substation.

What are the barriers to my doing that? Can I do that?

Chairwoman BIGGERT. Physically or legally?

Mr. CASTEN. Can I answer that?

Chairwoman BIGGERT. Sure.

Mr. CASTEN. First of all, the commission is going to say that it

is okay to charge you for 100 percent of all of the facilities to back

you up, because you might go down at the time of the absolute system peak. So you are going to pay for all of the wires anyway, and

this is going to mean you probably don’t want to do it. If they

charge maybe four percent, you would cover it.

73

Secondly, the power from that generation excess is going to flow

to the nearest user. It does by the laws of physics. But you will be

given a discounted amount for the extra power, based on what the

wholesale market is from big plants minus a discount because it is

too small to mess with. You will get no locational value for the fact

that your little operation is actually going to strengthen the local

grid. You will get no value for the fact that this is going to help

the big utility avoid the cost of putting another buried transmission—or distribution line in the street. So the commissions will

look at the costs only, not look at the benefits. And the net result

of all of that is that you will probably decide just to stay where you

are.

Dr. SMITH. Thank you.

Chairwoman BIGGERT. Thank you.

And if I might, I have one more question, and this is switching

gears a little bit, but as we proceed with our energy bill conference,

which I am a conferee and Mr. Lampson is a conferee, we will be

looking at authorization levels and which will be higher, but—for

these R&D programs. And in addition, in the electricity provision,

we are attempting to push the regulatory reforms that really

have—we have discussed here today. Which of these, in your view,

is of greater importance, the R&D or regulating reform? So I think

we will start with Mr. Glotfelty.

Mr. GLOTFELTY. I think they are equally important. The R&D

must continue, whether it is done at the basic level with the government and universities or the more applied level with industry,

to make sure that those technologies actually get deployed in the

grid. But they won’t be deployed into the grid unless we have the

regulatory reform. The cost that we are talking about of upgrading

the grid, if they cost $100 billion, may very well be offset by the

reduction in energy costs. If your bill is $100: $10 is transmission,

$10 is distribution, and $80 is energy, if we increase the transmission component or even the distribution component as well to

allow these other technologies and you decrease—and that incremental increase can very well be more than offset by a decrease in

energy costs. Distributed resources, demand response reduce costs

for everybody, not just the single user.

So I think they go hand in hand, and they both must be addressed as we move forward to make this system more reliable.

Chairwoman BIGGERT. Thank you.

Mr. Glauthier.

Mr. GLAUTHIER. I would note that the regulatory issues you are

dealing with are, of course, at the federal level. And as we said earlier, many of the issues that bear on the applications that we are

talking about are at the State level. So there may be a lot that can

be done through means of working with the states and not necessarily all through your legislation.

The organizations I represent are R&D organizations, so let me

speak to that part of your question and that is we do think that

increased authorization levels are appropriate here. And the levels

that are in the House-passed bill last year for the R&D and electricity area, we would increase or suggest increasing about $500

million a year. I mentioned earlier that we thought that the program ought to be $1 billion—I am sorry, $100 million a year, $500

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million over five years. That ought to be about $1 billion. There is

currently about half of that in those levels for these kind of programs. So we think it ought to be increased but not by the full

amount that I said. Importantly, I think it ought to be increased

to be transmission and distribution system R&D, not just for the

transmission system. The very things that we talked about here

that are really done at the customer level typically are through the

distribution system, and so it is important that the R&D do both.

We need to modernize the whole grid, not just half of it. And importantly, too, to include demonstration projects so that the Department can work with those utilities or those customers who are

at the leading edge of technologies and help support the first applications in order to get those technologies demonstrated and really

into working order.

So I would emphasize those three elements of the R&D program.

Chairwoman BIGGERT. Thank you.

Dr. Smith.

Dr. SMITH. I am sorry. I have no more comments on that, but I

may have another question later.

Chairwoman BIGGERT. Okay.

Dr. SMITH. I am learning here on some of this technology, okay.

My background—I do have an engineering—electrical engineering

degree, but it is from Cal Tech in 1949, and I don’t stay up. I am

doing economics, so I am really delighted with this——

Chairwoman BIGGERT. Well, we are delighted that you are here,

so thank you——

Dr. SMITH [continuing]. Interchange.

Chairwoman BIGGERT [continuing]. For your contribution.

Mr. Casten.

Mr. CASTEN. I would like to give you a very clean answer. The

regulation. The—a veritable Hoover Dam that holds back thousands of technologies that—many of which appropriations of this

committee over the years have helped to bring forward. But they

sit there. Let those flowers bloom and then we can do a better job

of figuring out what kind of new fertilizer we need. Right now, we

don’t know where those flowers are going to go, because they are

all held back. So fix the regulation first.

Chairwoman BIGGERT. Thank you.

Mr. LAMPSON. I want to go back to Dr. Smith’s question. What

is the solution? Is there a solution to this? Is there a way to reach

a point? Is total deregulation of letting anybody go out and do

whatever they want to do the answer? What——

Dr. SMITH. Well, regulation by—people are always regulated by

markets and prices. The question is how free should those prices

be? And Mr. Casten was saying that is—in answer to my question

here is we have these technologies, which also have the advantage

that they completely bypass the grid, so you don’t even have to use

this. You don’t have to worry about more investment in it. Although it still may be used as a backbone, as a backup, of course.

And there just isn’t the price incentive there for anyone to do it,

to invest in that, because of the local regulation. And I agree with

Mr. Glotfelty that the problem is really at the State level in the

kinds of issues we are here—that I am talking about. The problem

is at the State level, and that is why I am spending more of my

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time at that level and not up here testifying in Congress, because

I think that is where the problem is.

I think the danger, though, is that if that is not fixed at the

State level, then at the national level we will do things that are

not cost efficient because we are forced at the national level to invest in more supply side capacity and that is not at all—need not

at all be the most efficient way to create a more flexible system.

I don’t know whether it is feasible to—for the feds to simply declare that electricity is a commodity, whether it crosses State lines

or not, and gets in the business of separating wires from energy.

I think that is what we have to do. Energy is a commodity that can

be supplied competitively. And the local utility ties in the sale of

energy with the rental of the wires, and they have good motivation

to do that. But I believe that that should be—they shouldn’t—that

tie-in sale should not be taken for granted as a part of the regulatory apparatus. And that should be entirely opened up so that

the energy part can be supplied competitively, either with demand

interruption technologies and control or with generators closer to

the customer.

Mr. LAMPSON. Well, this has all been fascinating, and we have

lots more to learn, and I am sure that we will be spending a good

bit of time before we take the next steps, but thank you all for

being here, and thank you, Madame Chairman, for letting me participate.

Chairwoman BIGGERT. Before we bring the hearing to a close, I

would like to thank our panelists before the Subcommittee today.

You truly are experts, and we have—I think we have had a great

hearing, thanks to you. So if there is no objection, the record will

remain open for additional statements from the Members and for

answers to any follow-up questions the Subcommittee may ask the

panelists. Without objection, so ordered. The hearing is now adjourned.

[Whereupon, at 12:05 p.m., the Subcommittee was adjourned.]

(77)

Appendix 1:

ANSWERS TO POST-HEARING QUESTIONS

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ANSWERS TO POST-HEARING QUESTIONS

Responses by James W. Glotfelty, Director, Office of Electric Transmission and Distribution, U.S. DOE

Questions submitted by the Subcommittee on Energy

Q1. The creation of the new Office of Electric Transmission and Distribution separated R&D for transmission, distribution, and interconnection from R&D for

distributed generation. What was the reasoning behind this? How do you intend

to ensure that these R&D programs remain coordinated?

A1. The R&D division corresponds with appropriations subcommittee lines (distributed generation is under the Interior and Related Agencies Subcommittee; T&D is

under the Energy and Water Development Subcommittee). The new office includes

all of the activities previously funded in the Electric Energy Systems and Storage

activity in the Energy Supply account (EWD appropriation): high-temperature

superconductivity, energy storage, electric transmission reliability, and distribution

and interconnection. The Energy Conservation account (Interior appropriation)

funds R&D on industrial gas turbines, micro-turbines, reciprocating engines, and

materials and sensors for those engines and turbines.

Distributed generation is a critical component of a portfolio of technologies that

will help us over the next decade to achieve a more reliable and efficient electric

system. However, it will compliment and supplement existing generation, not supplant it entirely. Even if distributed generation contributes 20 or 30 percent of new

capacity additions in the Nation’s electric system over the next decade, hundreds

of gigawatts of electricity would still have to travel over the transmission system.

The new Office is committed to a secure, reliable, economic electricity system utilizing all of our generation assets and technologies. We will work closely with both

central generation (including large-scale renewables, coal, nuclear, natural gas) and

distributed generation. The program managers assigned to distributed generation

R&D and those assigned to transmission and distribution R&D will continue to

work closely together, share information, and participate in each other’s peer reviews.

Q2. In your testimony you state that distributed generation has important contributions to make, but will not be the single solution to reliability concerns. What

is your estimate of the size of the potential market for distributed generation?

Please include your assumptions about technology costs, etc.

A2. One estimate I have seen is that of Resource Dynamics Corporation, an energy

consulting company that utilizes an extensive set of tools including proprietary databases and models to develop innovative business solutions for energy technologies

and markets. Based on their analysis, today’s installed distribution generation is

169 gigawatts, which includes some 134 gigawatts of backup units which can be

used in the event of power supply failure. The distributed generation potential

(using current technologies) is about 80 gigawatts (which includes combined heat

and power and peak shaving, but does not include backup units). It grows to almost

180 gigawatts when future improvements in distributed generation technologies and

some more innovative applications (e.g., customer aggregation) are considered.

Q3. Last year the General Counsel for the North American Electric Reliability Council (NERC) testified that ‘‘Some entities appear to be deriving economic benefit

or gaining competitive advantage from bending or violating [NERC’s voluntary]

reliability rules.’’ Is there a technology remedy for this problem?

A3. Installing systems to monitor conditions regionally and respond to potential

problems more quickly is one remedy. High-speed, time-synchronized data systems

that are now being deployed could be used to track and predict the potential for outages in near-real time. However, this high-speed dynamic information could also be

used to do state estimation, system model improvement, and recalculate the ‘‘security’’ of grid in real time, providing the results to transmission providers for their

system and neighboring systems. If mandatory reliability standards were in place,

these systems could better detect non-compliance, and with the potential for penalties, the monitoring alone would provide incentive for compliance.

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Questions submitted by Minority Members

Q1. What sector makes up the largest percentage of electric load: household, industrial, commercial, etc.? In the next decade where will we see the largest increase

in efficiency? Where will we see the largest increase in demand?

A1. The Energy Information Administration (EIA) estimates that residential sector

comprises the largest percentage of electric load (roughly 36 percent), followed by

commercial (roughly 32 percent), and industrial sectors (roughly 29 percent).

On the upstream end of the supply line, energy efficiency involves getting the

most usable energy out of the fuels that supply the power plants. The EIA estimates

that nearly two-thirds of all energy used to generate electricity is wasted, with

transmission and distribution losses amounting to nine percent of gross generation.

Thus, combined heat and power, coupled with new technologies applied to the storage of energy and the transmission of electricity, will contribute to energy efficiency.

With respect to load, several energy efficiency programs at the Department affect

the commercial sector. These programs are designed to stimulate investment in

more efficient building shells and equipment for heating, cooling, lighting, and other

end uses.

According to EIA projections, the largest demand increases are expected in the

transportation sector (2.8 percent annual growth between 2001 and 2025, but with

a tiny fraction of the total electricity sales), followed by the three much larger electricity sales sectors: the commercial sector (a 2.2 percent annual growth between

2001 and 2025), the residential sector (a 1.6 percent annual growth between 2001

and 2025) and the industrial sector (also 1.6 percent annual growth between 2001

and 2025).

Q2. Despite the inevitable increases in efficiencies of household devices, do you believe demand per household will increase as more electronic devices are added

to average house and the average house gets bigger?

A2. Yes, but not at the rate of increase in the 1960s (over 7 percent). According to

the EIA (Annual Energy Outlook 2003, p. 66),

‘‘The continuing saturation of electric appliances, the availability and adoption

of more efficient equipment, and promulgation of efficiency standards are expected to hold the growth in electricity sales to an average of 1.8 percent per

year between 2001 and 2025. . .’’

Q3. You mention that reliability will be enhanced when grid operators are able to

make adjustments in real-time, to fluctuations in demand. Why are they not able

to do that now? In terms of personnel, what are the primary hurdles towards

achieving a smoother running system?

A3. Most of the electricity in our country is generated at the moment it is needed.

To meet changing electrical demands, some power plants must be kept idling in case

they are needed. These plants are known as ‘‘spinning reserves.’’ During times of

high electrical demand, inefficient power plants may be brought on-line to provide

extra power, and the transmission system may be stretched to near its limit, which

also increases transmission energy losses. Thus, today, adjustments to demand are

primarily made at the gross level (i.e., day-ahead markets, backed up by spinning

reserves).

Price responsive load, or demand response, programs could be more efficient in

responding to demand fluctuations in real-time. However, wholesale market and retail rules that allow grid operators to use demand response are limited. Retail pricing and demand response programs are largely controlled by the States, and it is

difficult for grid operators to influence them.

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ANSWERS TO POST-HEARING QUESTIONS

Responses by T.J. Glauthier, President and CEO, Electricity Innovation Institute,

Palo Alto, CA

Questions submitted by the Subcommittee on Energy

Q1. Which of the technologies you mention in your testimony could be deployed tomorrow on a mass scale? For the technologies that can’t be readily deployed,

what are the barriers to near-term implementation?

A1. One relatively simple technology developed by EPRI and successfully demonstrated by several utilities could contribute to improved system reliability by enabling increased confidence of safe loading levels for transmission lines above their

conservative static ratings. By integrating real-time sensor data on ambient temperature, wind speed, and line sag on specific circuits, EPRI’s Dynamic Thermal

Circuit Rating (DTCR) system allows operators to move more power on lines with

reduced risk of thermal overload. DTCR is low-cost and can be quickly deployed on

thermally constrained lines. Other near-term steps that could contribute to improved reliability include improved operator training, both for normal operation

under heavy loading conditions and for service restoration from outages.

On the hardware side, a mid-term solution for increasing the capacity of existing

transmission corridors may soon be ready for commercial deployment: advanced

high-temperature, low-sag conductors. These advanced conductors have the potential to increase current carrying capacity of thermally constrained transmission

lines by as much as 30 percent or more, and demonstrations are underway.

Loop flows can be controlled with solid-state power electronics technology, such

as Flexible AC Transmission Systems (FACTS) technology developed by EPRI and

power equipment vendors. However, FACTS technologies are still emerging and

their cost and size must be further reduced through continued R&D efforts before

they are economical for widespread deployment.

Development of a number of emerging technologies that are still not yet ready for

commercial deployment could benefit from increased industry and government support for demonstration efforts. These include the demonstration and integration of

new inter-system communication standards based on open protocols to enable data

exchange among equipment from different vendors, including SCADA and EMS systems. Two prime examples of such standards are the EPRI-developed Utility Communications Architecture for connecting equipment from different vendors and the

Inter-Control Area Communication Protocol for linking control centers and regional

transmission organizations.

A more complete description of how advanced technologies can help improve

power system reliability and what barriers need to be overcome is presented in the

EPRI report, Electricity Sector Framework for the Future—which may be

downloaded from http://www.epri.com/.

Q2. You’ve outlined several specific actions in your testimony that government, in

conjunction with the private sector, can take to ensure grid reliability in the future. What is the current level of investment in grid infrastructure by the private

sector and what should their investment be in the future. What about for R&D

investments?

A2. As discussed in the Electricity Sector Framework for the Future, Vol. 2, pp 29–

30, infrastructure investment levels relative to revenues are now below the levels

seen in the Depression of the 1930s, producing an ‘‘investment gap’’ of at least $20

billion a year. For example, electricity sector investments in transmission assets in

1999 were $3 billion, approximately half of what they were in 1979, and 30 percent

of the recent peak level reached in 1970. In October 2002, energy analysts at Oak

Ridge National Laboratory estimated that $56 billion of investments in transmission

infrastructure was needed in this decade just to maintain the current quality of

transmission service. The current level of capital expenditures is far short of this

minimum level.

Looking toward the future, EPRI recommends a research and demonstration program that will require increased federal funding for R&D on the scale of approximately $1 billion, spread out over five years, with the private sector contributing

a significant amount of matching funding. These R&D and demonstration funds represent an investment that will stimulate deployment expenditures in the range of

$100 billion from the owners and operators of the smart grid, spread out over a decade.

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Q3. What is your estimate of the size of the potential market for distributed generation? Please include your assumptions about technology costs, etc.

A3. Most estimates show distributed energy resources (DER) eventually representing 10–20 percent of U.S. total generation, depending on a variety of assumptions. EPRI does not have its own estimate. Rather, we have focused on determining

the market potential of DER in particular applications. Specific findings include:

• New DR applications for baseload electric-only and co-generation are fairly

limited. Economics for these applications are only favorable in areas with

very high electric prices, low gas prices, and sites with good electric and thermal load profiles.

• Future peaking applications may offer important opportunities for using DER.

For example, peaking DER can be applied in combination with a number of

different electricity contract types, including time-of-use rates (to avoid buying power during peak price periods), interruptible rates (to sustain operations during outages), flat rates (to present a flatter load profile to the electricity seller), and rates with peak demand charges (to reduce peak demand).

• Significant opportunities may exist for selling DER for backup power to businesses that have not traditionally used DER for such applications.

• DER projects that provide multiple solutions to a customer (e.g., heat and

electricity) are much easier to justify economically. When considering a DER

project, all potential benefits need to be explored and economically quantified.

In Attachment A, ‘‘Analysis of DER Applications Potential,’’ Table 1 shows the results of our analysis for baseload electric, co-generation and peaking power DER potential in the industrial and commercial sectors. Tables 2–4 show the assumptions

involved in the analysis.

Ouestions submitted by Minority Members

Q1. If it is going to take ten years or more to get the smart grid developed and implemented, are there steps we need to be taking to make the current grid more reliable in the interim. Are we adding complexity through distributed power? Do we

need to go slow on this or other innovations?

A1. Although ultimately revolutionary in its effect, the smart grid will be evolutionary in its development. Some pieces—e.g., current utility applications of DTCR and

FACTS—are already being put into place. Others, such as the Dynamic Risk and

Reliability Management (DRRM) system, which would enable system operators to

react quickly to grid conditions that threaten to cause outages, will require that a

sophisticated system monitoring and communications systems to be implemented

first. It is therefore vital that government and the private sector to work in partnership in demonstrating and deploying new technologies in an orderly fashion. Specifically, EPRI is already engaged with several utilities partners to demonstrate DRRM

tools on their transmission systems, and we propose a public-private initiative to

hasten their widespread deployment.

The role of DER in improving power system reliability is complex. In general—

everything else being equal—the closer that power is generated to loads, the greater

potential for high reliability. Put another way, the longer the lines used to delivery

power, the more potential there is for interruptions. Conversely, however, if DER

is not integrated properly with the existing grid, both reliability and safety may be

jeopardized. For example, linemen may be injured if power flows in an unexpected

direction along a distribution line because of a DER unit on a customer’s premises.

To make sure that increased use of DER supports reliability and safety, EPRI is

helping develop new interconnection standards (discussed in more detail below) and

is working to make individual DER units more ‘‘plug and play’’ compatible with existing power systems. In the language of the question—the point is not to go slowly,

but to go carefully.

Q2. We set up safety margins in other lifeline institutions. For instance, in the banking industry, a certain percentage of the financial assets of a bank must be kept

as reserves, and energy generation reserves are a long-established practice in the

industry. Do we need similar limits on percentage of resources that can be used

with regard to transmission capacity?

A2. A distinction should be made between infrastructure capacity versus

consumable resources. Bank reserves and fuels for electricity are consumables,

which can be used to reduce the probability of it running out. Power plant capacities

and transmission capacities, on the other hand, represent fixed infrastructure, reVerDate 11-MAY-2000 22:27 Apr 21, 2004 Jkt 089419 PO 00000 Frm 00085 Fmt 6601 Sfmt 6621 C:\WORKD\ENER03\092503\89419 SCIENCE1 PsN: SCIENCE1
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quiring long lead time for construction. Because they are highly capital intensive,

it is not economical to overbuild by a large degree. And once these facilities are

built, the costs are sunk, so it makes no economical sense not to make use of them

for normal operation. An analogy is building a highway with more lanes than currently needed. It does not make sense to block off a lane from normal usage and

hold it in reserve.

Because generator and transmission capacities have measurable probabilities of

outages, however, extra generators and lines are needed for backup when outages

occur. In this way, the backup units that are not directly affected by an outage will

generally be sufficient to keep most of the grid intact and deliver power economically.

In the case of setting safety margins for generation capacity, the rule of thumb

is that for most regions, a 15 to 20 percent reserve margin (based on the annual

peak load forecast) would be adequate. With transmission, however, there is no comparably simple reserve margin to compute, because the loading of the transmission

lines changes frequently in response to economic dispatch or wholesale power market fluctuations. Flows can go in one direction at one time and then in the opposite

direction some other time. Lines are often loaded to the maximum operating limit.

If the demand and the wholesale power market cause certain transmission lines to

be loaded above their operating limits, then the grid operators can usually re-dispatch the generation or curtail the wholesale power transactions so as to keep the

loadings below the operating limits. The extreme remedial action would be to curtail

firm customer loads.

The question thus arises of how to set transmission operating limits, based on the

concept of providing an adequate safety margin. NERC requires that no transmission line or transformer should become loaded above its reliability limit upon the

sudden outage of another single transmission line or transformer, anywhere else in

the grid. This requirement is known as the ‘‘single-contingency criterion.’’ For example, if two transmission lines serve an isolated area, then the loss of one of the two

lines must not result in overloading the remaining line. For example, if each of the

two lines can carry 100 MW of power, then the maximum amount of load they can

serve together under this criterion is only 100 MW. Most of the time, when both

lines are in service, they will share the load between them—each carrying 50 MW,

with 50 MW of spare capacity. Then, if one line goes down, the other can safely

carry the full 100 MW load.

The single-contingency criterion is based on the assumption that if a line outage

happens, the operator will know about it immediately and take corrective action to

bring the system to a safe operating condition where with the possible onset of another line outage, the system is still reliable. The rating of the transmission line’s

operating limit is based on this reaction time. For thermal overloads, the rating is

typically based on the ability to sustain 30 minutes of this load level without physical damage or without sagging onto trees, causing a short circuit. Thus, if either

the monitoring equipment fails to notify the operator, or the corrective action cannot

be taken within the 30 minutes to relieve the overload, this single contingency criterion will not be adequate.

The blackout of August 14, 2003 has brought these two potential problems into

visibility. First, alarm systems or state estimators could fail to notify the operator.

Second, the re-dispatch or curtailment process may either not work properly due to

bad data or too lengthy a communication process. Thus, to compensate for these potential factors, it may perhaps be necessary either to re-examine the definition of

the operating limits, or to change the single-contingency criterion to a double-contingency criterion, or to a probabilistic reliability criterion. In any case, it is likely that

this will result in the need for more transmission investment so as to provide the

additional safety margin.

Further information about efforts to improve grid reliability in response to the

dramatic increases in inter-regional bulk power transfers that have resulted from

industry restructuring is presented in Assessment Methods and Operating Tools for

Grid Reliability: An Executive Report on the Transmission Program of EPRI’s Power

Delivery Reliability Initiative. [Note: This report appears in Appendix 2: Additional

Material for the Record.]

Q3. Are there areas where our standards development is inadequate and is there a

federal role in funding the development of consensus standards organizations

that work with your industry?

A3. Industry and government have a long history of working together closely with

standards-making organizations, such as the Institute of Electrical and Electronic

Engineers (IEEE). Recent work on the IEEE 1547 Standard for Interconnecting Distributed Resources with Electric Power Systems provides an excellent example. The

83

three-year effort has been fully supported by the power industry, EPRI, the U.S. Department of Energy, and other stakeholders.

This new standard establishes the technical foundation for the interconnection of

all distributed energy resources (DER) with electric power systems. It ensures that

major investments in DER technology development by the power industry and government organizations will result in real-world applications providing alternative

sources of electric power to the electric utility operating infrastructure. The IEEE

standard may be used in federal legislation and rule-making, in state PUC deliberations, and by more than 2,500 electric utilities in formulating technical requirements for interconnection agreements.

The efforts and commitment of the many stakeholders were instrumental in the

fast-track success of the standard and in the implementation of the complementary

1547 body of standards-development activities. EPRI and numerous other organizations have hosted the meetings, and many companies have supported the participation of their employees. Altogether, the 1547 Working Group has involved more than

350 members. To further aid in the safe and reliable integration of DER with electric power systems, the Group is currently working on a series of ancillary standards related to testing (P 1547.1), applications (P 1547.2), and communications (P

1547.3).

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ANSWERS TO POST-HEARING QUESTIONS

Responses by Thomas R. Casten, CEO, Private Power, LLC, Oak Brook, IL; Chairman, World Alliance for Decentralized Energy

Questions submitted by the Subcommittee on Energy

Q1. Which states or regions—or countries do a good job of supporting distributed

generation? Why do you think this is?

A1. No U.S. state does a good job. New York, personally encouraged by Governor

Pataki, has developed standard interconnection rules for very small DG and has

started to address standby power. California, reeling from shortages and brownouts,

has claimed support for DG and offers some avoidance of penalty rates for small

DG.

However, several countries are doing a surprisingly good job in supporting DG.

Portugal leads in leveling the playing field. The single national grid company is required to purchase DG under a formula that considers the avoided cost of central

generation, the transmission capital saved by local generation, the transmission

losses saved by DG, the impact of recycling heat from DG on pollution, and the

availability of the DG. By contrast, no state in the U.S. gives any credit to the DG

plant for any costs beyond avoided cost of central generation, ignoring the savings

of T&D capital and losses and the pollution savings.

Indian regulators have had a recent epiphany, recognizing that the country is

starved for power, has up to 50 percent losses in the grid (compared to 10 percent

in U.S. on average) and that one of the country’s major industries, sugar cane, could

produce significant power without fossil fuel, saving imports and carbon emissions.

One-year-old policies provide 13-year contracts for DG at full value and require the

local grid to pay half of the costs of interconnecting with these local generators.

China, operating in a command and control mode, does not allow new factories

to build boilers for thermal energy when there is a nearby power plant that can supply waste thermal energy. China increased power output over the prior decade by

roughly 45 percent, but actually reduced CO2 emissions by nearly 15 percent in the

same decade by promoting more efficient DG.

In general, I think the public and its leaders accept the central generation paradigm without much thinking and the monopoly protected utilities, beneficiaries of

the resultant practices, find it in their interest to maintain the laws and approaches

that prevent more efficient, but competitive DG. When a polity comes under intense

pressure, all assumptions come under question. New York lost industrial jobs and

‘‘enjoyed’’ nation leading high electric prices and began to change. California power

crises caused thinking. Indian poverty finally toppled conventional wisdom.

Q2. What steps should the Federal Government take to allow distributed generation

and combined heat and power to compete fairly?

A2.

• Reshape all debate to consider the delivered cost of power.

• Use antitrust laws to vigorously oppose state rules that limit private wires

or otherwise prevent DG from competing to supply customers with electric

power.

• Revamp EPA rules to focus on permit limits and allowance trading programs

based on pollution per megawatt hour of useful electricity or thermal energy,

applicable equally to all heat and power generation, eliminating all grandfather rules, legacy pollution permits and differences between types of plants

and age of plants. This will reward efficiency and force the industry to build

power plants close to users where thermal energy can be recycled.

• Focus research and development support on energy recycling technologies,

which are inherently DG.

• Exercise federal jurisdiction over power regulation as the interstate commerce

it truly is. This will lessen the power of local monopolies to preserve anti-competitive rules and should lead to more functional markets.

Questions submitted by Minority Members

Q1. What future role do you see for the national laboratories in helping to fulfill

your goal of building more local power, building smaller units and recycling

waste energy? Are there specific programs in the laboratories that should be better funded or redirected to produce the needed technologies?

87

A1. There has been very little work done by industry or the labs on the technologies

that recycle low-density waste energy. Industry rejects vast quantities of exhaust

heat that does not support economical electric generation with conventional Rankine

cycle steam plants, but which has higher quality than the typical geothermal field.

Technology does exist (organic fluid Rankine cycle) to recycle this heat. Small technical improvements would help economics.

The proof of feasibility for recycling can be found in a typical geothermal field.

A California geothermal project described by LBL taps thermal energy from the

ground to produce 40 megawatts of electricity. A 250-megawatt coal fired power

plant exhaust contains the same quantity and quality of energy in its exhaust, and

could, using current organic fluid Rankine cycle generation, produce an added 40

megawatts with no added fuel. Without the subsidies received for ‘‘renewable’’ energy by the geothermal installation and using today’s technology, it has not made

economic sense to recycle coal exhaust. The labs could work on increasing the efficiency and capital efficacy of low temperature recycling, which would lead to

myriads of DG plants wherever factories exhaust waste heat.

The labs, especially LBL, have documented some of the potential to recycle waste

energy from U.S. industry and gathered information about how other more efficiency focused societies do a better job of recycling energy from steel, primary metals, foundries, glass production, etc. The results are in obscure technical papers that

never reach policy makers or the general public. The labs could popularize this information to great advantage.

Q2. You list as one of your approaches (page 4) to finding solutions the need for

standardized interconnection access for distributed energy sources.

A2. There are, according to DOE, over 6,000 DG plants that supply nine percent

of U.S. energy, all of which are interconnected with the grid. Yet, every new DG

plant proponent, with the exception of a few very small plants that fall under standard rules in Texas, NY, and Massachusetts must go through extensive hearings and

subject their designs to individual approval by the local utility, which has financial

incentive to prevent the existence of a new competitor. These hearings are filled

with dire warnings of the dangers to the utility workers and suggestions that without extraordinary prudence, the DG plant could trip the entire grid. Yet, to my

knowledge, there are no known cases of utility workers being electrocuted by DG

plants or of DG plants causing grid failure. In fact, the connection of a one-megawatt electric motor has nearly the same impact on the grid as a one-megawatt generator. For the motor, there are national standards, incorporated in local codes, and

no hearing is needed. For the generator, the process could take up to 18 months

and a great deal of money. DG will not improve U.S. standards of living or reduce

U.S. fuel use and pollution until there are national standards for interconnection

of all sizes of DG.

Q3. What are the unresolved technical issues associated with standardized interconnections? Do new technologies need to be developed to ensure that these interconnections will function more safely and seamlessly?

A3. In private conversations, the utility personnel assigned to interconnection debates admit that there are no major technical issues, only commercial issues.

Change the rules to make the utility operating the distribution grid embrace efficiency and energy recycling, and the interconnection technical issues will all go

away. See above regarding over 6000 installations, per DOE, and add the unnoticed

100,000 back pressure turbines that generate electricity in parallel with the grid (industry data). It is common for the utility community to insist that there are great

and deep technical issues, because legally trained regulators lack the confidence to

overrule utilities on safety issues.

The new technologies most in need of development are hybrid direct current supply systems for computer intensive users, and the control technology needed to

blend on-site power with grid backup to increase the reliability of power from its

present state, which was designed for the industrial motor requirement, to today’s

needs for power quality by computers and servers. These technologies, as already

deployed, start with any type or quality of incoming power, invert that power to DC

and then prepare conditioned alternating current. Advances in direct current distribution and control will make DG the obvious economic choice and move the focus

away from unfounded safety issues to very real economic and efficiency concerns.

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ADDITIONAL MATERIAL FOR THE RECORD

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