[House Hearing, 108 Congress]
[From the U.S. Government Publishing Office]
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
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______
COMMITTEE ON SCIENCE
HON. SHERWOOD L. BOEHLERT, New York, Chairman
LAMAR S. SMITH, Texas RALPH M. HALL, Texas
CURT WELDON, Pennsylvania BART GORDON, Tennessee
DANA ROHRABACHER, California JERRY F. COSTELLO, Illinois
JOE BARTON, Texas EDDIE BERNICE JOHNSON, Texas
KEN CALVERT, California LYNN C. WOOLSEY, California
NICK SMITH, Michigan NICK LAMPSON, Texas
ROSCOE G. BARTLETT, Maryland JOHN B. LARSON, Connecticut
VERNON J. EHLERS, Michigan MARK UDALL, Colorado
GIL GUTKNECHT, Minnesota DAVID WU, Oregon
GEORGE R. NETHERCUTT, JR., MICHAEL M. HONDA, California
Washington CHRIS BELL, Texas
FRANK D. LUCAS, Oklahoma BRAD MILLER, North Carolina
JUDY BIGGERT, Illinois LINCOLN DAVIS, Tennessee
WAYNE T. GILCHREST, Maryland SHEILA JACKSON LEE, Texas
W. TODD AKIN, Missouri ZOE LOFGREN, California
TIMOTHY V. JOHNSON, Illinois BRAD SHERMAN, California
MELISSA A. HART, Pennsylvania BRIAN BAIRD, Washington
JOHN SULLIVAN, Oklahoma DENNIS MOORE, Kansas
J. RANDY FORBES, Virginia ANTHONY D. WEINER, New York
PHIL GINGREY, Georgia JIM MATHESON, Utah
ROB BISHOP, Utah DENNIS A. CARDOZA, California
MICHAEL C. BURGESS, Texas VACANCY
JO BONNER, Alabama
TOM FEENEY, Florida
RANDY NEUGEBAUER, Texas
------
Subcommittee on Energy
JUDY BIGGERT, Illinois, Chair
CURT WELDON, Pennsylvania NICK LAMPSON, Texas
ROSCOE G. BARTLETT, Maryland JERRY F. COSTELLO, Illinois
VERNON J. EHLERS, Michigan LYNN C. WOOLSEY, California
GEORGE R. NETHERCUTT, JR., DAVID WU, Oregon
Washington MICHAEL M. HONDA, California
W. TODD AKIN, Missouri BRAD MILLER, North Carolina
MELISSA A. HART, Pennsylvania LINCOLN DAVIS, Tennessee
PHIL GINGREY, Georgia RALPH M. HALL, Texas
JO BONNER, Alabama
SHERWOOD L. BOEHLERT, New York
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
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
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
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.
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?
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 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.
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 on-site 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?
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?
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.
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 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.
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.
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.
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, high-temperature 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 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 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 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 President'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. Long-distance 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:
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 multi-year, 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 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 ``first-responders'' 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 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.
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 steel-core 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 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 mid-Atlantic 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 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 power-flow 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.
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 real-time 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 large-scale 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, high-voltage situations.
Benefits: These storage systems behave like conventional
generation and have the benefit of producing additional
generation sources that can be dispatched 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 systems 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.
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 low-speed data access for the utility's infrastructure.
Building a network of high-speed 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 (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.
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 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 General 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, 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, real-time
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.
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 real-time 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 RoomTM software, Transformer 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.
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.
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.
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.
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 81/2 cents and as low as
11/2 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 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.
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:
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.
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
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 deja 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
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.
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 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 21/2 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.
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 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 advantages 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
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 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.
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 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.
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\
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\1\ Thomas R. Casten and Martin J. Collins, Recycled Energy: An
Untapped Resource, April 19, 2002.
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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 NOX 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 bankruptcy 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.
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.
---------------------------------------------------------------------------
\2\ Prices given in 1996 dollars as reported at www.eia.doe.gov
---------------------------------------------------------------------------
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 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.
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: [email protected]
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 describe 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, low-energy 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 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.
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 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 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.
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 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 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 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 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.
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 NOX, 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 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
transmission 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 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.
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 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 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.]
Appendix 1:
----------
Answers to Post-Hearing Questions
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.
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.
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.
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, requiring 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 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).
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?
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.
Appendix 2:
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Additional Material for the Record
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