[House Hearing, 108 Congress]
[From the U.S. Government Publishing Office]
FUTURE OPTIONS FOR GENERATION OF ELECTRICITY FROM COAL
=======================================================================
HEARING
before the
SUBCOMMITTEE ON ENERGY AND AIR QUALITY
of the
COMMITTEE ON ENERGY AND COMMERCE
HOUSE OF REPRESENTATIVES
ONE HUNDRED EIGHTH CONGRESS
FIRST SESSION
__________
JUNE 24, 2003
__________
Serial No. 108-32
__________
Printed for the use of the Committee on Energy and Commerce
Available via the World Wide Web: http://www.access.gpo.gov/congress/
house
__________
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COMMITTEE ON ENERGY AND COMMERCE
W.J. ``BILLY'' TAUZIN, Louisiana, Chairman
MICHAEL BILIRAKIS, Florida JOHN D. DINGELL, Michigan
JOE BARTON, Texas HENRY A. WAXMAN, California
FRED UPTON, Michigan EDWARD J. MARKEY, Massachusetts
CLIFF STEARNS, Florida RALPH M. HALL, Texas
PAUL E. GILLMOR, Ohio RICK BOUCHER, Virginia
JAMES C. GREENWOOD, Pennsylvania EDOLPHUS TOWNS, New York
CHRISTOPHER COX, California FRANK PALLONE, Jr., New Jersey
NATHAN DEAL, Georgia SHERROD BROWN, Ohio
RICHARD BURR, North Carolina BART GORDON, Tennessee
Vice Chairman PETER DEUTSCH, Florida
ED WHITFIELD, Kentucky BOBBY L. RUSH, Illinois
CHARLIE NORWOOD, Georgia ANNA G. ESHOO, California
BARBARA CUBIN, Wyoming BART STUPAK, Michigan
JOHN SHIMKUS, Illinois ELIOT L. ENGEL, New York
HEATHER WILSON, New Mexico ALBERT R. WYNN, Maryland
JOHN B. SHADEGG, Arizona GENE GREEN, Texas
CHARLES W. ``CHIP'' PICKERING, KAREN McCARTHY, Missouri
Mississippi TED STRICKLAND, Ohio
VITO FOSSELLA, New York DIANA DeGETTE, Colorado
ROY BLUNT, Missouri LOIS CAPPS, California
STEVE BUYER, Indiana MICHAEL F. DOYLE, Pennsylvania
GEORGE RADANOVICH, California CHRISTOPHER JOHN, Louisiana
CHARLES F. BASS, New Hampshire TOM ALLEN, Maine
JOSEPH R. PITTS, Pennsylvania JIM DAVIS, Florida
MARY BONO, California JAN SCHAKOWSKY, Illinois
GREG WALDEN, Oregon HILDA L. SOLIS, California
LEE TERRY, Nebraska
ERNIE FLETCHER, Kentucky
MIKE FERGUSON, New Jersey
MIKE ROGERS, Michigan
DARRELL E. ISSA, California
C.L. ``BUTCH'' OTTER, Idaho
Dan R. Brouillette, Staff Director
James D. Barnette, General Counsel
Reid P.F. Stuntz, Minority Staff Director and Chief Counsel
______
Subcommittee on Energy and Air Quality
JOE BARTON, Texas, Chairman
CHRISTOPHER COX, California RICK BOUCHER, Virginia
RICHARD BURR, North Carolina (Ranking Member)
ED WHITFIELD, Kentucky ALBERT R. WYNN, Maryland
CHARLIE NORWOOD, Georgia THOMAS H. ALLEN, Maine
JOHN SHIMKUS, Illinois HENRY A. WAXMAN, California
Vice Chairman EDWARD J. MARKEY, Massachusetts
HEATHER WILSON, New Mexico RALPH M. HALL, Texas
JOHN SHADEGG, Arizona FRANK PALLONE, Jr., New Jersey
CHARLES W. ``CHIP'' PICKERING, SHERROD BROWN, Ohio
Mississippi BOBBY L. RUSH, Illinois
VITO FOSSELLA, New York KAREN McCARTHY, Missouri
STEVE BUYER, Indiana TED STRICKLAND, Ohio
GEORGE RADANOVICH, California LOIS CAPPS, California
MARY BONO, California MIKE DOYLE, Pennsylvania
GREG WALDEN, Oregon CHRIS JOHN, Louisiana
MIKE ROGERS, Michigan JOHN D. DINGELL, Michigan
DARRELL ISSA, California (Ex Officio)
C.L. ``BUTCH'' OTTER, Idaho
W.J. ``BILLY'' TAUZIN, Louisiana
(Ex Officio)
(ii)
C O N T E N T S
__________
Page
Testimony of:
Alix, Frank, Chief Executive Officer, Powerspan Corp......... 87
Black, Charles R., Vice President, Energy Supply, Engineering
and Construction, Tampa Electric Company................... 56
Burke, Frank, Vice President, Research and Development,
Consol Energy, Inc., on behalf of the National Mining
Association................................................ 17
Courtright, Henry A., Vice President, Power Generation and
Distributed Resources, Electric Power Research Institute... 27
Ferguson, J. Brian, Chairman and Chief Executive Officer,
Eastman Chemical Company................................... 50
Hawkins, David G., Director, Climate Center, Natural
Resources Defense Council.................................. 75
McDonald, Lawrence E., Director, Design Engineering and
Technology, The Babcock & Wilcox Company................... 70
Olliver, Richard A., Group Vice President, Global Energy Inc. 65
Rudins, George, Deputy Assistant Secretary for Coal and Power
Systems, U.S. Department of Energy......................... 12
Rush, Randall, Power Systems Development Facility Director,
Southern Company........................................... 60
Yoon, Roe-Han, Director, Center for Advanced Separation
Technologies, Virginia Tech................................ 83
Additional material submitted for the record:
Rush, Randall, Power Systems Development Facility Director,
Southern Company, letter dated July 10, 2003, enclosing
response for the record.................................... 110
(iii)
FUTURE OPTIONS FOR GENERATION OF ELECTRICITY FROM COAL
----------
TUESDAY, JUNE 24, 2003
House of Representatives,
Committee on Energy and Commerce,
Subcommittee on Energy and Air Quality,
Washington, DC.
The subcommittee met, pursuant to notice, at 2 p.m., in
room 2123, Rayburn House Office Building, Hon. Joe Barton
(chairman) presiding.
Members present: Representatives Barton, Burr, Whitfield,
Norwood, Shimkus, Boucher, Allen, Waxman, Brown, McCarthy,
Strickland, and Doyle.
Staff present: Bob Meyers, majority counsel; Andy Black,
policy coordinator; Bob Rainey, fellow; Bruce Harris, minority
counsel; and Michael L. Goo, minority counsel.
Mr. Barton. The subcommittee will come to order. We are
waiting for a minority member to arrive, but we will officially
start the hearing.
The subcommittee will come to order. Without objection, the
subcommittee will proceed pursuant to committee rule 4(e) which
governs opening statements by members and the opportunity to
defer to them for extra questioning time. Any objection?
Hearing none, prior to the recognition of the first witnesses
for testimony, any member when recognized for an opening
statement may completely defer his or her 3-minute opening
statement and instead use those 3 minutes during the initial
round of the witness questioning. In other words, they will get
8 minutes instead of 5.
The Chair is going to recognize himself for an opening
statement.
More than half of our Nation's electricity is generated
from the combustion of coal and power plants. Our coal reserves
are tremendous and should last more than 250 years given the
current expectation for the use of coal. In other words, coal
power is here to stay. Coal plants today are much more
efficient than they ever have been and they emit much less per
ton of coal consumed than they ever have before. The act of
generating electricity from coal, however, is a process that
can stand further comment and research.
Today the subcommittee is going to take a look at the
future options for generating electricity from coal. The
hearing is intended as a technical hearing on future options
and we are pleased to have a distinguished set of witnesses on
these technical issues. Members of the subcommittee need to be
aware of the latest technology applications that are available
to electricity generators today, what might be available in the
future.
We have witnesses today to discuss coal gasification,
advanced combustion boilers, environmental controls and other
new concepts. Some of our witnesses can discuss the process
that a generator will go through when making a decision on
these future options.
Congress has a role to play in this debate. H.R. 6, the
House Energy bill which passed the House back in April and
which is pending in the Senate, many Members of both political
parties embraced the Clean Coal Power Initiative. Leaders of
that initiative are on this subcommittee: Mr. Shimkus, Mr.
Boucher, Mr. Whitfield, Mr. Strickland, Mr. Doyle and others.
The Clean Coal Power Initiative provides for continuation
of public/private partnership in finding improved methods to
produce electrical power from coal, including an emphasis on
coal gasification technology. We have also identified tax
credit provisions that will encourage utilities to employ these
new technologies. I have talked with a number of members about
an enhanced clean coal program to aggressively implement
retrofits and entirely replace some of the old existing coal
plants with next-generation facilities. This particular idea is
not in a pending bill that is in the Senate, but it is an idea
that could be if there is enough support for it.
I will work with all members in the energy conference on
the clean coal section, the tax title and other conference
items, incorporating, to the extent possible, lessons that we
learned from today's hearing.
Since committee consideration of H.R. 6, the Department of
Energy has announced a new initiative regarding the future
generation from coal. This FutureGen Initiative calls for
public/private partnership which design, construct, and operate
a 275-megawatt prototype plant that produces both electricity
and hydrogen with near zero emissions and with sequestration of
carbon dioxide emissions.
Our hearing today will offer the opportunity to review this
proposal for interaction with other clean coal initiatives and
the projected benefits and costs of such technology. I want to
welcome all of our witnesses today and encourage you to give us
an honest picture of what you think the future of coal use in
the United States looks like. I expect we can explore what kind
of power plants will be available to power generators in the
next few years and what kind of power plants will be feasible
in the longer term.
We can also examine the congressional role in authorizing
such activity, in providing for the conditions which will lead
to adoption of new coal-based electric power plants for the
private sector.
Finally we also want each of the witnesses to explain to us
what they think will work and what doesn't work and what
efforts Congress should support or not support. These answers
are important. This hearing will have a great impact on the
positions that members of the Energy and Commerce conference
committee take in the discussions we have with our Senate
comrades when they pass their bill, hopefully sometime this
month or perhaps in July or even September.
We should not and will not take coal off the table either
directly or through an overly burdensome regulatory structure.
We should and can continue the evolution of coal generation
into the 21st century. When we talk about abundant reliable and
affordable energy, coal today is a major part of that debate,
and should be for the rest of our lives and our children's
lives. The question is how best to do this. Where are the
currently available technologies, the technology that will
become available in the near term, and the future technologies
which can best utilize our Nation's most abundant conventional
energy resource.
With that I would like to recognize Ranking Member Boucher,
for an opening statement and thank him for helping put this
hearing together. Many of the witnesses today are here because
of his suggestion that they attend.
Mr. Boucher. Thank you very much, Mr. Chairman, and I want
to express my appreciation to you and the members of your staff
for the outstanding cooperation you have provided in scheduling
this hearing and assembling outstanding witnesses for us today.
And I want to say a word of welcome to each of our witnesses.
At a hearing before the full committee earlier this month
on the topic of natural gas supply and demand, we heard from
the Energy Information Administration that by the year 2025, it
is estimated that an additional 450 gigawatts of new
electricity generation capacity will be needed in order to meet
rising demand. Even with far higher prices for natural gas in
recent years and the related concerns regarding the long-term
availability of a stable supply of natural gas, it is still
predicted that 80 percent of the new power plants to be
constructed between now and 2025 will be powered with natural
gas. One of the reasons that natural gas is so widely used for
electricity generation is the fuels environmental performance.
But at the same time, it should be noted that advances in
clean coal technologies, both recently achieved and on the
horizon, are ensuring that future coal-fired electricity plants
will be able to operate with little environmental effect.
Coal is the Nation's most abundant fuel, with reserves
sufficient for the next 250 years in the United States alone at
current consumption rates. It generates electricity at less
than one-half the cost of the fuel alternatives. In fact today,
coal delivered to the power plant costs $1.25 per million BTUs
as compared to natural gas that costs $4.50 per million BTUs.
$1.25 for coal, $4.50 for natural gas. Natural gas prices are
predicted to remain at this level or to rise in the foreseeable
future, while it is estimated that coal prices will fall even
further.
It is clearly in the energy security interest of the Nation
to use coal, an abundant domestic resource, and consumers
clearly get the best prices for electricity when they purchase
electricity generated through the combustion of coal.
We are also mindful of the harm to the national economy
that will occur with the rapid rise of gas prices, which would
be a certain consequence of the deployment of hundreds of new
gas-fired electricity-generating units. More than one-half of
homes are heated today with natural gas. Products throughout
the economy are manufactured in natural gas consuming and
intensive processes. A dramatic increase and the demand for
natural gas occasioned by an overreliance on gas for
electricity generation will cause serious economic harm.
Accordingly, we should be doing everything we can to encourage
fuel alternatives to natural gas. We simply cannot tolerate the
use of natural gas as the fuel for 80 percent of the new
electricity-generating units to be built over the next 20
years.
Several of us, members of this committee, have suggested a
path to a solution, and I was pleased that the chairman
mentioned that effort in his opening remarks. We had hoped to
make possible the greater use of coal for electricity
generation and relieve the pressure on natural gas pricing that
will occur unless Congress takes positive steps.
Earlier this year, I was pleased to join with several
colleagues on this committee, including the gentleman from
Kentucky, Mr. Whitfield and the gentleman from Illinois, Mr.
Shimkus, and other members in introducing the Clean Coal Power
Act of 2003. Our legislation acknowledges the value to the
Nation of coal use and takes appropriate steps to assure the
protection of air quality where coal is burned. Our legislation
makes a substantial Federal investment in coal research and
development and also provides tax benefits to promote the use
of coal in both new and retrofitted electricity-generating
plants that agree to use advanced clean coal technologies.
Today we will hear from a number of witnesses regarding the
successes of clean coal technologies and what future
technologies will further advance the use of coal, and I look
forward to their testimony on this topic.
I want to take just a moment, Mr. Chairman, to say a
special word of welcome to two of our witnesses. Dr. Roe-Han
Yoon is a world leader in coal research and development. He is
a department head and professor at Virginia Tech, which happens
to be in my congressional district. He is here not because he
is my constituent, but because of the expertise that he
possesses in a wide range of research and development fields
relating to clean coal technology. He serves as executive
director of the Center for Advanced Separation Technologies, a
consortium of a number of universities focusing on more
efficient use of coal through precombustion separation
technologies.
I also want to say a word of welcome to Mr. Brian Ferguson,
chief executive officer of the Eastman Chemical Company. His
company is a chemical producer, a very large one at that, which
operates the Nation's first commercial coal gasification
facility. The Eastman experience in the commercial use of coal
gasification is clearly of relevance to our focus today and may
suggest a positive direction for this committee to consider,
and I want to welcome Mr. Ferguson as well.
Mr. Chairman, you have assembled an excellent panel of
witnesses. I thank you for scheduling this hearing and I look
forward to the testimony of those who come before us.
Mr. Barton. It is easy to do when we ask the people you
ask. Works pretty well that way.
Mr. Barton. Does the gentleman from Georgia wish to make an
opening statement?
Mr. Norwood. Thank you, Mr. Chairman, and I want to thank
you and Mr. Boucher for putting this hearing on and I plan to
do a lot more listening than talking.
Mr. Barton. Then you will have an additional 3 minutes on
your questions.
Does the gentleman from Ohio wish to make an opening
statement?
Mr. Brown. I will have more talking than listening.
Mr. Barton. The gentleman is recognized--we are not going
to put the clock on you, but supposedly you are supposed to
talk for 3 minutes.
Mr. Brown. I thank the witnesses for what I expect will be
informative testimony. I am particularly pleased that we are
joined today by two witnesses with close ties to my State of
Ohio. Babcock & Wilcox headquartered in Barberton Ohio leads
the industry in production of boilers for coal-fired power
plants and the emissions control systems designed for single
pollutant and multipollutant applications. B&W is researching a
promising advanced combustion technology called oxyfuel that
may make conventional coal combustion much more compatible with
greenhouse gas emissions control. We are proud to have B&W and
proud to have Larry McDonald, the company's director of Design
Engineering Technology here today.
Powerspan is a valued partner to First Energy which is
headquartered in Akron, Ohio in my district. Powerspan's
electrocatalytic oxidation technologies produce promising test
results as an effective and cost-effective multipollutant
control technology. Emissions reductions of 80 percent to well
over 90 percent in an economic package clearly merit further
study. Along with our colleague Ted Strickland, a member of
this committee, I support Powerspan's production scale tests at
First Energy's plant near Shadyside, Ohio. I am pleased that
Powerspan's CEO, Frank Alix, was able to appear here today.
So as I consider coal's future as a source of electric
power, the dynamic seems grounded in three fundamental points:
One, coal is here to stay. Two, coal can and must be an
environmentally responsible source of fuel for the generation
of electric power. Three, the Federal Government must support
research and require the market to develop innovative,
effective, and affordable pollution control technologies.
Coal is here to stay because it is an affordable, readily
available source of domestic energy. This committee's recent
examination of natural gas prices illustrates abandoning coal
would compromise our energy security and our industrial
competitiveness. As this committee's ongoing interest in
manipulation of western energy markets amply illustrates,
failure to maintain a diversified fuel mix invites abuse in the
marketplace, sometimes with disastrous results.
The economic stakes are much too high for Congress to offer
less than a total commitment to the continued viability of
coal. Coal can be cleaner than it is today. There are already
well-established pollution control technologies of Babcock &
Wilcox as well as the promising efforts of Powerspan to offer
significant improvements in the environmental performance of
traditional coal-fired power plants.
The first thing the Federal Government must do is maintain
and expand upon the sponsorship of promising research. Like the
chairman and Ranking Member Boucher, I enthusiastically support
the Clean Coal Power Initiative and I believe we must maintain
the effort to improve the emissions performance of existing
coal-fired plants. As Powerspan and B&W have both demonstrated,
we can achieve meaningful improvements.
Congress should continue to support promising research to
make America's existing coal-fired plants cleaner. It is
essential that Congress, in addition, sponsor research to
develop tomorrow's low-end, zero emissions, coal-fueled
generating technologies. Coal gasification research has been
encouraging to date and the clean coal program should continue
to explore this technology.
In addition, although I rarely agree with President Bush on
some of his energy policies, I couldn't agree more with the
Energy Department's FutureGen proposal. FutureGen offers a
government/industry partnership to address the challenges of
developing coal-based fuel cell power plants. Ohio's power
companies have already committed to this project. Ohio's
universities are doing leading edge technology research on fuel
and fuel cells. Congress should provide the resources necessary
to take zero emissions technology from the drawing board to the
production line.
Mr. Chairman, today's hearing offers valuable insights into
one of the most important energy issues confronting our Nation.
Mr. Barton. We may let you Chair this hearing, you know,
supporting the President and all this. That is front page news,
you know.
Does the gentlelady from Missouri wish to make an opening
statement?
Ms. McCarthy. I have a lengthy one, so let me just list
from it briefly so that we can proceed with our witnesses.
I want to thank you for having this hearing. Missouri--82
percent of our electric power out in Missouri comes from coal.
And I just want to brag a minute about what happened in my
district, Kansas City, because Kansas City Power and Light
Hawthorne generating station was old, was in need of either
tearing down or improving, and as a result of efforts to change
the way we do business, it has become one of the cleanest coal-
fired plants in the United States. This facility, that was
rebuilt, has 88 percent lower nitrogen oxide, 99 percent lower
particulate matter, and 92 percent lower sulfur dioxide
emissions than any other uncontrolled facility. And the
Hawthorne generating station is a model of clean coal
technology that can be used for the rest of our Nation.
So, Mr. Chairman, I join my colleagues in supporting the
Clean Coal Power Initiative and to make sure that Congress
keeps funding initiatives like the Hawthorne plant and that we
do the continuing research for FutureGen and other ways in
order to provide the energy needed across our country, but also
do so in an environmentally friendly way. I welcome the experts
here today and look forward to their testimony and yield back.
Mr. Barton. Does the gentleman from Kentucky wish to make
an opening statement?
Mr. Whitfield. Yes, I do Mr. Chairman.
Mr. Barton. The gentleman is recognized for 3 minutes.
Mr. Whitfield. Mr. Chairman, thank you very much. And I
want to thank you and Mr. Boucher for having this very
important hearing on our most abundant and inexpensive resource
that we have in America today, and that is coal.
The timing of the hearing couldn't be better. We have heard
in the last few weeks from administration officials, including
Federal Reserve Chairman, Mr. Greenspan, and we have read
countless market analyses who are telling us the same thing:
that natural gas prices are going to continue to go up and that
the demand is not there to meet the needs of our country.
But as the price of natural gas and the rate that it is
used for electric power generation rises, coal-fired power
generation has decreased. Even though coal continues to be our
country's primary electric power source, the share of power
generation has dropped from 56 percent in 1997 to 49 percent
last year. In that same time period, gas-fired power generation
doubled from 9 to 18 percent. The same uncertainty about
environmental regulations that cause this decline is also
responsible for the fact that over the last 8 years, only 3500
megawatts of new coal capacity have come on line. This fact is
particularly alarming because the Energy Information
Administration estimates that by 2025, America will need an
additional 1.9 trillion kilowatt hours per year. Basically what
this means is that we have an artificially induced market for
natural gas primarily because of a lot of environmental
regulations.
But the value of coal as a power source for our country is
almost infinite. A four-county area in my district alone has 15
percent more energy in coal reserves than the Nation has in
proven reserves of natural gas. Still, the economic impact of
coal to my State and a number of others is massive. In 2000,
Kentucky's coal industry's impact on the State economy totaled
almost $7 billion.
I am delighted that we are having this hearing today. We
are going to hear from a number of experts, that we can and
should better utilize existing clean coal technologies and
invest in future technologies that will do more of what is
already being done, and that is reduce harmful emissions.
Congressman Boucher, Mr. Shimkus, Mr. Strickland, Ms.
Cubin, and I co-authored a bill, the Clean Coal Power Act of
2003. This forward-looking legislation addresses our Nation's
increasing electricity demand by enhancing the research,
development, and early commercial application of advanced clean
coal technologies. Our bill would include short, medium, and
long-term programs to improve efficiency and further reduce
emissions while also ensuring that we will have the coal-
generating capacity required to meet the increased demands of
the future. It is both beneficial to the environment and
critical to our future economic and electrical needs.
Mr. Chairman, I look forward to the testimony of our
witnesses, and I do want to emphasize once again that we must
be more aware of our most abundant resource and do everything
that we can do to continue to provide electricity at an
affordable rate, and the best way we can do that is to use
clean coal technologies and burn more coal.
Mr. Barton. Thank you.
Does the gentleman from Pennsylvania wish to make an
opening statement?
Mr. Doyle. Mr. Chairman, I want to commend you for holding
this hearing and I would like to waive my opening statement and
return for some extra time.
Mr. Barton. The gentleman will get an additional 3 minutes
in the first question period.
Does the gentleman from Illinois wish to make an opening
statement?
Mr. Shimkus. I don't need to waive. I will just say that I
want my statement for the record, and just talk about the whole
energy bill process and what we are trying to do with the
energy bill is we got to expand the grid. That is a critical
component. Our hearing on natural gas proved that we have been
too overreliant on one fuel. And I have always pushed for a
multifuel approach in meeting our energy needs. And coal has an
important and critical role at the table, especially for
baseload generation. And we need to do all that to make sure
that is part of our national security and energy generation.
And I look forward to the hearing.
And with that, Mr. Chairman, I yield back my time.
[The prepared statement of Hon. John Shimkus follows:]
Prepared Statement of Hon. John Shimkus, a Representative in Congress
from the State of Illinois
If the past is any indication, the future is not bright for coal.
The number of mining jobs related to coal continues to decrease every
year. Over 90% of all new power plants are fired by natural gas. The
fact that we have not given a national energy policy to the President
yet, only matters worse as industry waits on some certainty from
Congress.
However, I continue to believe that coal can play a vital role in
our nation's energy future. We can change the future here in Congress.
If we continue to focus on increasing research on ways to burn coal
more efficiently and cleaner, and we stop killing coal use by
regulation, coal will have a bright future.
This Administration and this Congress have started to put the
resources behind finding ways to burn coal more efficiently and
cleaner. The energy bill that passed the House contains over $2 billion
to fund research on clean coal technologies over the next 10 years. The
Administration's FutureGen proposal will lead to power plants that will
burn coal without emitting pollution. Using the latest technology, they
will generate electricity, sequester greenhouse gases, and provide a
new source of clean-burning hydrogen.
In Illinois we have 2 projects that are harnessing new developments
in coal generation technologies to burn coal cleaner, both involved
different gasification technologies.
The first one at Dynegy's Wood River plant would use the Ashworth
Combustor, a front-end gasification technology that provides for multi-
pollutant control. On a small demonstration project, the technology
achieved results which included 70%+ reduction in sulfur dioxide
emissions, NOX emissions below 0.15lb/million Btu, and
mercury reductions of over 90%. The technology allows older coal plants
to be retrofitted to burn cleaner, eliminating the hassle of permitting
a new power plant.
The second project uses coal gasification in a 2600 MW plant which
will produce almost zero emission and as a by-product, will produce
over 175,000 barrels a day of low sulfur diesel fuel. The facility will
also mine close to 30 million tons of coal annually.
These two projects represent the future of coal. Both would greatly
reduce emissions, both continue to use coal, both would add high paying
mining jobs, and both follow the vision that this Administration has
put forth on a diversified energy portfolio that relies on domestically
produced energy resources.
Mr. Chairman, the future of coal can be bright. But Congress needs
to step up and send an energy bill to the President that includes
funding for research and tax credits for implementation. I yield back
the balance of my time.
Mr. Barton. Seeing no other member present, Chair would ask
unanimous consent that all members' opening statements be put
into the record at the appropriate point. Without objection, so
ordered.
[Additional statements submitted for the record follow:]
Prepared Statement of Hon. W.J. ``Billy'' Tauzin, Chairman, Committee
on Energy and Commerce
An affordable and reliable electricity supply is a critical
cornerstone of the American economy, providing the foundation for much
of our prosperity. Even as we seek to improve the efficient use of
energy and make environmental gains, the link between energy production
and economic growth has been clear, with both being critical to our
nation's wellbeing.
It is also clear that our economy has suffered when supplies of
affordable energy have tightened. Whether it be gasoline prices
sporadically and regionally above $2 dollars a gallon, $10 natural gas
during the winter of 2001, or $35 dollar a barrel oil in 1981, price
spikes in energy supplies have been felt in the bottom line of the
American economy and in the homes of nearly all Americans.
Just two weeks ago, in this committee room, Alan Greenspan warned
of the economic challenges that may lie ahead with respect to natural
gas. While he expressed optimism in the long run, short term prices
have exceeded $6 per million BTU and the long-term equilibrium price of
natural gas has risen steadily over the last six years.
So it is of no small import that we examine future options for coal
use during today's hearing. Fifty-three percent (53%) of our
electricity comes from coal, and, by all accounts, coal is expected to
remain a very important source of energy for decades into the future.
While we have also made substantial use of electricity from nuclear,
oil, gas and to a lesser extent renewable energy sources, coal remains
a leading cost-effective option for electric generation.
In this vein, projections made by the Energy Information
Administration indicate that coal use in the U.S. will grow about 30%
over the next two decades, roughly matching the pace of growth of total
energy consumption in the U.S. An independent study conducted in 2002
also concluded that in 2010, coal will contribute over $400 billion to
the nation's output and be responsible for 3.6--million jobs.
So, the question might be asked, if things really look so promising
for coal use, why are we holding this hearing? If the future is bright,
what's the problem? The answer is that the future won't happen by
itself. We as a nation will need to make several important commitments
that, over the long term, will assist in the efficient use of coal in
an environmentally responsible manner.
For as central as coal is to the generation of our nation's
electricity, the fact of the matter is that over 90% of new U.S. power
plants over the past few years have been fueled by natural gas. This
surge in demand is part of the reason for higher natural gas prices,
but even with this price signal, relatively few new coal units are
currently being planned by the nation's utilities. There are many
separate reasons for this situation; however, an important and vital
part of the eventual solution is the availability of new options for
coal generation that are considered to be viable in the private
marketplace.
Today, we will receive testimony about clean coal technology that
has to potential to revitalize, perhaps even revolutionize, the use of
coal for electric power generation. Our first panel will address the
Clean Coal Power Initiative and the FutureGen program that has been
proposed by the President. Both of these programs are designed as
public/private partnerships to explore new methods to generate
electricity from coal. The FutureGen program is especially far-
reaching, having a goal of a ``near zero'' emission coal plant.
Our second panel contains experts in coal, coal generation
technology and the utilization of this technology in ``test bed''
facilities as well as the real world. They bring with them a wealth of
professional experience and I know that the Subcommittee can benefit
greatly by their insights.
Altogether, we will not answer each and every question concerning
coal at today's hearing. But I believe this hearing provides an
important opportunity for us to listen and learn. As a Committee with
broad jurisdiction in this area, we need to assess what technologies
may be viable today, what may become available in the near term, and
what is realistically on the horizon. Only with this understanding can
we make the best commitment of our nation's resources.
I want to welcome all of our witnesses and I look forward to their
informed testimony.
______
Prepared Statement of Hon. Ralph M. Hall, a Representative in Congress
from the State of Texas
Mr. Chairman and Members of the Committee--I thank you for holding
this hearing today on the use of coal for electric power generation. It
is, after all, our largest domestic energy source and one in which we
have turned our back on in recent years. The rest of the country
discovered several years ago what we have known in Texas for many
years--that with current technologies natural gas is safe, reliable,
and can be burned with lower overall emissions in plants that cost less
to build than a comparably sized coal plant.
However, it is now clear that the time has come when natural gas
will not be able to meet the incremental demands for electric power--
certainly not at prices that we have come to expect. Simply put, as gas
becomes more expensive, coal becomes more competitive. As a nation we
need to recognize that now is the time to begin to make the big
investments in research and development in technologies that will to
allow us burn coal in plants that reduce air emissions to as low a
level as possible.
I hope that the promise of the ``FutureGen'' project can be
fulfilled, which is to build a plant that is essentially emissions-
free. However, I am concerned that even as ambitious as the
Administration's Clean Coal Power Initiative is, that--even at the
funding level of $200 million a year contained in H.R.6--it may not be
enough to be able to build and have an emissions free power plant in
service by 2020. We need to recognize that this program is going to
cost more in the out years than we're providing for today if it is to
meet its goals.
As you know, I'm an oil and gas guy, but I'm also a coal, nuclear,
renewables and a conservation and efficiency guy, too. My provisions in
H.R. 6 establish a crash program to develop the technologies needed to
drill and produce natural gas and oil in the ultra-deep and
unconventional onshore areas of this country. There's huge potential--
as much as 69 trillion cubic feet of natural gas alone, according to
one study--enough to fill more than one-third of the gap between gas
supply and demand that is expected to develop between now and 2015.
We need to fund R&D in all of these technologies if we are to
maintain the quality of life and standard of living that we have come
to expect. We need to stop fighting over a diminished pot of money and
recognize that our national welfare demands that we enlarge the pot so
that no deserving energy technology is starved out of federal R&D
funding.
Mr.Chairman, I yield back the balance of my time.
Mr. Barton. The Chair would also ask unanimous consent that
a statement pertaining to the use of petroleum coke, by Dr.
Hans Linhardt be put into the official record. Is there
objection? Hearing none, so ordered.
[The prepared statement of Hans Linhardt follows:]
Prepared Statement of Hans D. Linhardt, President, Linhardt Technology
Development International, Inc.
The shortage of natural gas (``NG'') has driven the price from 3$/
MMBTU to over $6/MMBTU. Most recent Clean Power and Hydrogen Projects
in the U.S. depend on NG feed, thus demanding increased product prices
from the public. Increased hydrogen prices also lead to increased end
product prices of gasoline and low sulfur diesel.
Recent legislation is considering to develop advanced technology
for the production of clean hydrogen and power from coal via the
gasification process (``FuterGen''). Also tax credits have been set
aside for clean power production from coal.
Petroleum coke (``petcoke'') has not been considered by the
legislature and is being exported from the US. The US refineries
produce about 125,000 st/d of petcoke per day with a lower heating
value of 15,250 BTU/lb and an order of magnitude less ash than US coal.
This would translate to 20,000 MW of clean power and/or replacement of
five nuclear plants of 4,000 MW capacities.
Fig. 1 presents an overview of the petcoke production by US
refineries. Petcoke production is predominant in the major population
centers of the US, where clean fuels and clean power are demanded by
the legislature.
Gasification is basically a refinery type of process (Shell &
Texaco), that benefits significantly from integration with the petcoke
producing refineries when compared with grassroots clean coal power
plants (using gasification).
A typical example of the advantages and environmental benefits of
petcoke gasification is the LA Basin Project, which plans to gasify
about 8000 st/d of petcoke from refineries located close to the LA and
Long Beach Harbor for the net production of 700 MW of clean power and
200 MMSCFD of hydrogen for production of clean fuels by the refineries.
Since the petcoke price is about constant, no price spikes are
envisioned for petcoke based clean power and fuel production in
contrast to the severe price spikes of NG based power and hydrogen
plants.
The LA Basin Project (feasibility established; financing for Phase
II depending on legislation) would significantly reduce the shipping
and handling of coke to and from the LA Harbor, thus reducing serious
coke dust and related health issues in the Harbor area. Of course,
clean low cost power is welcomed by all surrounding communities.
Hydrogen is the live blood of the refineries, assuring reliable
operation and control of operating costs.
San Francisco, Houston and New Orleans would derive the same
benefit as the LA Harbor, as well other communities close to refinery
centers.
The feasibility of petcoke gasification has been established by
Shell and Texaco and no government funding is required to build a state
of the art advanced clean power plant with hydrogen co-production and
control of CO2 emission. However, the tax credits currently being
offered for coal should also be available for petcoke, in order to
facilitate financing of projects, from $500 million to $1.6 billion. A
tax credit of 1 cent/KWh for clean electricity and $0.25/MSCF of clean
hydrogen would certainly be a significant incentive for developers and
refineries to proceed with petcoke to hydrogen and power projects.
Mr. Barton. We want to welcome our first panel. Let me make
a brief introduction. We first have the Deputy Assistant
Secretary for Coal and Power Systems in the Office of Fossil
Energy at the United States Department of Energy, George
Rudins. I am informed that Mr. Rudins has an excellent
reputation as a technical expert and has been the manager of
the clean coal program for the Department of Energy for a
number of years. We appreciate your appearance. Understand that
you are a professional career staffer and not a political
appointee and, as such, wouldn't be able to answer any
political questions for the Bush administration. Of course, you
are entitled to your own opinion, and if they ask a political
question you can certainly give us a political answer if you
want to.
We also have Dr. Frank Burke, who is the Vice President of
Research and Development at the--at CONSOL Energy. Dr. Burke is
testifying today on behalf of the National Mining Association.
CONSOL Energy and other National Mining Association members
have been a part of various public/private partnership efforts
ongoing regarding clean coal technology, including specifically
the Clean Coal Power Initiative and now FutureGen. So we are
glad that you are here.
We have Mr. Hank Courtright who is the Vice President for
Power Generation and Distributed Resources at the Electric
Power Research Institute, better named to this committee as
EPRI. It is a nonprofit, collaborative research organization
supported by the electric power industry. It has engaged in
broad research and development efforts on behalf of the
industry and the public for over 30 years. And I believe you
are headquartered out in California, so we are glad to have
you.
We are going to start with you, Mr. Rudins. Give you 7
minutes and give each of the other gentleman 7 minutes and then
we will have some questions. Welcome to the subcommittee.
STATEMENTS OF GEORGE RUDINS, DEPUTY ASSISTANT SECRETARY FOR
COAL AND POWER SYSTEMS, U.S. DEPARTMENT OF ENERGY; FRANK BURKE,
VICE PRESIDENT, RESEARCH AND DEVELOPMENT, CONSOL ENERGY, INC.,
ON BEHALF OF THE NATIONAL MINING ASSOCIATION; AND HENRY A.
COURTRIGHT, VICE PRESIDENT, POWER GENERATION AND DISTRIBUTED
RESOURCES, ELECTRIC POWER RESEARCH INSTITUTE
Mr. Rudins. Thank you, Mr. Chairman and members of the
committee. In addition to offering my written testimony for the
record, I have a short opening statement I would like to make.
Mr. Barton. Without objection.
Mr. Rudins. I am pleased to appear before the subcommittee
today to discuss the role that new clean coal technologies can
play in helping the Nation meet ever-increasing demands for
energy in the most efficient and environmentally responsible
manner possible.
With much of the Nation's attention again focused on the
security of global energy supplies, it is important to remember
that we remain an energy-rich country. Today, coal is an
indispensable part of our Nation's energy mix. Because of its
abundance and low costs, coal accounts for half of the
electricity generated in our country today.
Since I joined ERDA, DOE's predecessor agency, close to 30
years ago, there has been dramatic progress in clean coal
technology and power generation technology in general. The
average national total cost of electricity since 1983 has come
down approximately 30 percent from 9.2 cents per kilowatt hour
in 1983 to 6.4 cents in the year 2000. As a result, the
development of new clean coal technology I had the formidable
challenge of not only striving to improve efficiency of power
generation while meeting ever tighter environmental
regulations, but it had to be done while keeping the cost of
electricity competitive with conventional plants that were
coming down in costs.
Clean coal technology development, which involved efforts
by both DOE and industry, more than met this formidable
challenge. New, lower-cost emission control systems were
successfully developed, demonstrated and deployed. Low
NOX burners, for example, are now deployed on close
to 75 percent of the plants capable of using them. The cost of
SO2 scrubbers and selective catalytic reduction
systems, or SCR for short, have been greatly reduced, while the
performance of these systems has been greatly increased. This
technology has kept the cost of coal-based electricity to
consumers low while greatly reducing environmental emissions.
As a result, coal used for power generation has roughly tripled
since 1970, while overall emissions have decreased by over 30
percent. And new coal power plants emissions show an even
greater percentage of decrease in emissions on an individual
plant basis.
In terms of clean coal power generation technologies, back
in the mid-seventies, we could not even foresee the dramatic
advances in technology that have already occurred and the
revolutionary progress that we are now poised to achieve in the
not-too-distant future. In addition to government and industry
successfully developing atmospheric fluidized bed combustion
plants that have become one of the work horses of the coal
power industry, the investment we have collectively made over
the last 30 years on gasification-based systems has taken this
technology to the point that U.S. taxpayers are already
starting to reap the benefits.
Two integrated gasification combined-cycle power plants, or
IGCC for short, have been successfully demonstrated under the
clean coal program and have entered commercial service. They
are among the most efficient and cleanest coal plants ever
built. The 30-year clean coal technology base that has been
developed, together with these successes, will enable
gasification-based technologies to make even further and more
rapid advances in the future.
The average efficiency of the existing fleet of coal power
plants is in the 33 percent range. The integrated gasification
combined cycle plants now operating that I just referred to
have efficiencies close to 40 percent, with very low emissions.
In the future, IGCC plants can reach 60 percent efficiencies
and even higher efficiencies in combined heat and power
applications.
From an emissions viewpoint, we believe advanced IGCC
systems can approach zero emissions when integrated with carbon
sequestration. And if we can achieve our development goals,
these systems can do so while electricity generation costs are
maintained at competitive levels.
FutureGen represents the ultimate manifestation of a zero
emissions plant that coproduces electricity and hydrogen. I
would like to take a minute to draw you a verbal picture of
FutureGen. In the FutureGen approach, we start with coal which
is converted to a synthesis gas, which is basically hydrogen,
carbon monoxide, and carbon dioxide in a gas-fired vessel. We
run that mixture of gases through a shift reactor to change the
carbon monoxide into more hydrogen and carbon dioxide. At this
point, we can separate the useful hydrogen from carbon dioxide
and route the carbon dioxide for disposal. The hydrogen can
then be used to produce power, be converted to chemicals like
ammonia fertilizer, or be used as a transportation fuel in
vehicles using fuel cells. If we return to the carbon dioxide
that has been routed for disposal, we can send it to a deep
saline geologic structure for storage; or, if we are in the
right location, we can get a further return on our investment
by using it for enhanced oil recovery. In short, FutureGen
provides us with technology to use coal to make a spectrum of
energy products, including hydrogen, with essentially no
pollution and no greenhouse gas emissions.
Achievement of FutureGen goals is a major challenge that is
made more manageable by prior government and industry successes
with clean coal technology. There has been much industry
experience with many of the components required for FutureGen.
For example, there are hundreds of operating gasifiers
worldwide. There has been much experience with shift reactors,
gas turbines and so on. What makes FutureGen a major challenge
is that in order to achieve its goals, we must push the
technology envelope for most of these components well beyond
their current capability and then put them together for the
first time into an integrated system with components just
emerging from the laboratory, such as low cost CO2
capture and storage technology. But the public benefit when we
succeed will be enormous. In order to assure that FutureGen is
successful, it will be supported by a clean coal R&D effort
focused on all key technologies needed, such as carbon
sequestration, membrane technologies for oxygen and hydrogen
separation, advanced turbines, fuel cells, coal-to-hydrogen
conversion, gasifier related technologies and other
technologies. And, the Clean Coal Power Initiative, funding for
which is included in the administration's 2004 budget request,
will help drive down the costs of IGCC systems and other
technologies critical to the success of FutureGen through
demonstration of key technologies. With each technology
replication, lessons are learned, refinements are made, and
costs decrease for the next unit built.
In summary, I would like to suggest that successes in
improving efficiency, reducing emissions, and reducing emission
control costs in the coal sector is largely due to technology
developed by an effective government/industry partnership, and
that this same partnership can define a future for coal in
which Americans can continue to reap the benefits of this
abundant and low-cost domestic resource. It is technologically
possible, through a continued and sustained coal R&D effort
with a focus on FutureGen, to cost effectively produce hydrogen
and electricity from coal with essentially zero emissions, and
thereby provide not only clean electricity from coal but also
clean hydrogen for a future transportation fleet. This will be
a remarkable achievement for U.S. Science and technology. This
would indeed be coal's Holy Grail.
This concludes my opening remarks. Thank you for the
opportunity to address the committee, and I will be pleased to
answer your questions.
[The prepared statement of George Rudins follows:]
Prepared Statement of George Rudins, Deputy Assistant Secretary for
Coal and Power Systems, Office of Fossil Energy, U.S. Department of
Energy
Mr. Chairman and Members of the Subcommittee: I am pleased to
appear before the Subcommittee today to discuss the great potential new
technology will play in helping the Nation meet ever increasing demands
for energy in the most efficient and environmentally responsible manner
possible.
With much of the Nation's attention again focused on the security
of global energy supplies, it is important to remember that we remain
an energy-rich country. Today, coal is an indispensable part of our
Nation's energy mix. Because of its abundance and low cost, coal now
accounts for more than half of the electricity generated in this
country.
Coal is our Nation's most abundant domestic energy resource. One
quarter of the entire world's known coal supplies are found within the
United States. In terms of energy value (Btus), coal constitutes
approximately 95 percent of U.S. fossil energy reserves. Our nation's
recoverable coal has the energy equivalent of about one trillion
barrels of crude oil--comparable in energy content to all the world's
known oil reserves. At present consumption rates, U.S. coal reserves
are expected to last at least 275 years.
Coal has also been an energy bargain for the United States.
Historically it has been the least expensive fossil fuel available to
the country, and in contrast to other primary fuels, its costs are
likely to decline as mine productivity continues to increase. The low
cost of coal is a major reason why the United States enjoys some of the
lowest electricity rates of any free market economy.
America produces over 1 billion tons of coal per year. Nearly all
of it (965 million tons) goes to U.S. power plants for the generation
of electricity.
According to the Energy Information Administration, annual domestic
coal demand is projected to increase by 394 million tons from the 2001
level of 1.050 billion tons to 1.444 billion tons in 2025, because of
projected growth in coal use for electricity generation.Largely because
of improving pollution control technologies, the Nation has been able
to use more coal while improving the quality of the air. While annual
coal use for electric generation has increased from 320 million tons in
1970 to more than 900 million tons, sulfur dioxide emissions from coal
have dropped from 15.8 million tons annually to 10.7 million tons in
2000, the most current year available. In addition, particulates from
coal-fired plants declined some 60 percent over the same period
according to the Environmental Protection Agency.
Because coal is America's most plentiful and readily available
energy resource, the Department of Energy (DOE) has directed major
portions of its R&D resources at finding ways to use coal in a more
efficient, cost-effective, and environmentally benign manner.
National Benefits of Clean Coal
It is not widely known how far clean coal technologies have come in
reducing emissions from coal-fired power plants, or how far we can go
over the next few years. For example, in 1970, overall coal-based
electric power generation emission rates were 4.4 pounds
SO2/million British Thermal Units (mmBtu) and 0.95 pounds
NOX/mmBtu. In 2000, the rates were 1.0 pounds
SO2/mmBtu and 0.44 pounds NOX/mmBtu.
The ability to meet today's emission limits, and the cost of that
compliance, has been greatly improved. For example, in the 1970's, most
options for significantly reducing smog-forming nitrogen oxide
(NOX) pollutant emissions were untried and expensive--in
some cases, costing as much as $3,000 per ton of pollutant removed.
Now, the cost of the retrofit low-NOX burners is estimated
at less than $200 per ton. Similarly, the costs of flue gas
desulphurization units--or ``scrubbers''--have been dramatically
reduced and their reliability greatly improved.
New government-industry collaborative efforts are getting underway
pursuant to both our traditional R&D program and the President's Coal
Research Initiative. These programs will continue to find ways to
improve our ability to limit emissions from power generation, at lower
costs. The goal for future power plant designs, such as FutureGen,
discussed later in my testimony, is to remove environmental issues from
the fuel choice equation by developing coal-based zero emission power
plants. Moreover, the focus is on designs that are compatible with
carbon sequestration technology.
The Next Generation of Power Plants
In the 1970's, the technology for coal-fired power plants was
generally limited to the pulverized coal boiler--a large furnace-like
unit that burns finely ground coal. As part of DOE's Clean Coal
Technology Program, DOE and industry have demonstrated higher fuel
efficiencies and superior environmental performance. For example,
rather than burning coal, it could be gasified--turned into a
combustible gas. In gaseous form, pollutant-forming impurities can be
more easily removed. Like natural gas, it could be burned in a gas
turbine-generator, and the turbine exhaust used to power a steam
turbine-generator. This ``combined cycle'' approach raised the
prospects of unprecedented increases in fuel efficiency. Gasification
combined cycle (IGCC) plants built near Tampa, Florida (TECO Project),
and West Terre Haute, Indiana (Wabash River Project), are among the
cleanest, most efficient coal plants in the world. The Wabash River
Project, which is a repowering of an existing coal-fired unit, resulted
in a 30-fold decrease in SO2 and a 5-fold decrease in
NOX emissions. These projects have recently completed their
demonstration phases and are entering commercial operations.
The progress to date in developing IGCC systems, especially with
the two clean coal demonstration projects now in commercial service,
has laid the foundation for broader application of IGCC and continuing
advances in IGCC technology--the ultimate manifestation of which is
FutureGen.
FutureGen--Zero Emissions From Cutting Edge Technology
Earlier this year, President Bush and Secretary of Energy Abraham
announced plans for the United States to build with international and
private sector partners a prototype of the fossil fuel power plant of
the future called FutureGen. It is one of the boldest steps toward a
pollution-free energy future ever taken by our nation and has the
potential to be one of the most important advances in energy production
in the first half of this century.
This prototype power plant will serve as the test bed for proving
out the best technologies the world has to offer. Virtually every
aspect of the prototype plant will be based on cutting-edge technology.
FutureGen will be a cost-shared $1 billion venture that will
combine electricity and hydrogen production with the virtual
elimination of emissions of such air pollutants as sulfur dioxide,
nitrogen oxides and mercury, as well as carbon dioxide, a greenhouse
gas.
The Department envisions that FutureGen would be sized to generate
the equivalent of approximately 275 megawatts of electricity, roughly
equal to an average mid-size coal-fired power plant. It will turn coal
into a hydrogen-rich gas, rather than burning it directly. The hydrogen
could then be combusted in a turbine or used in a fuel cell to produce
clean electricity, or it could be fed to a refinery to help upgrade
petroleum products.
It will provide other benefits as well. FutureGen could provide a
zero emissions technology option for the transportation sector--a
sector that accounts for one-third of our nation's anthropogenic carbon
dioxide emissions.
In the future, the plant could become a model for the production of
coal-based hydrogen with zero emissions to power the new fleet of
hydrogen-powered cars and trucks President Bush spoke about during his
State of the Union address and called for by his Hydrogen Initiative.
Using our abundant, readily available, low-cost coal to produce
hydrogen--an environmentally superior transportation fuel--would help
ensure America's energy security.
Carbon sequestration will be one of the primary features that will
set the FutureGen plant apart from other electric power projects.
Engineers will design into the plant advanced capabilities to capture
the carbon dioxide in a form that can be sequestered in deep
underground geologic formations. No other plant in the world has been
built with this capability.
Once captured, carbon dioxide will be injected deep underground,
perhaps into the brackish reservoirs that lay thousands of feet below
the surface of much of the United States, or potentially into oil or
gas reservoirs, or into unmineable coal seams or volcanic basalt
formations. Once entrapped in these formations, the greenhouse gas
would be permanently isolated from the atmosphere.
The project will seek to sequester carbon dioxide emissions at an
operating rate of one million metric tons or more of carbon dioxide
sequestered per year. We will work with the appropriate domestic and
international communities to establish standardized technologies and
protocols for carbon dioxide measuring, monitoring, and verification.
The FutureGen plant will pioneer carbon sequestration technologies
on a scale that will help determine whether this approach to 21st
century carbon management is viable and affordable.
In April 2003, the Department's notice of request for information
on the plan to implement FutureGen appeared in the Federal Register.
Comments were requested by June 16, and we are currently reviewing
them. The ultimate success of FutureGen depends on acceptance of the
concept of sequestration by the industry that will have primary
responsibility for its potential future implementation.
The Department plans to enter into a cooperative agreement with a
consortium led by the coal-fired electric power industry and the coal
production industry. Under the guidance of a government steering
committee, this consortium will be responsible for the design,
construction and operation of the FutureGen plant, and for the
monitoring, measuring, and verifying of carbon dioxide sequestration.
The Federal Register notice indicates that members of a qualifying
consortium must collectively own and produce at least one-third of the
nation's coal and at least one-fifth of its coal-fueled electricity. In
addition to collectively owning and producing a large fraction of the
national coal and electricity, the consortium is expected to be:
(a) Geographically diverse by including both eastern and western
domestic coal producers and coal-fueled electricity generators;
and,
(b) Be resource diverse by including producers and users of the full
range of coal types.
The public's interest is best served by having this broad cross-
section of the coal and coal-fueled electricity industries involved in
this project. The Department will require that the consortium use fair
and open competition in selecting the host site and the plant
components. The Department also is seeking the participation of other
coal consuming and producing nations in the FutureGen initiative at
this week's the Carbon Sequestration Leadership Forum. Broad
involvement in the project is desired to achieve wide acceptance of the
concept of coal-based systems integrated with sequestration technology.
Although the consortium will be limited to coal and coal-fueled
electricity generation owners and producers, and while equipment and
service vendors may participate through a competitive selection process
for their goods and services, the Department expects the consortium to
provide mechanisms for future participation in the project, as
appropriate, of interested parties such as state governments,
regulators, and the environmental community.
We also expect the consortium to be open, working to expand its
initial membership to one that is inclusive and open to other coal and
coal-fueled electricity owners and producers. We anticipate placing
separate contracts to independently validate carbon dioxide
sequestration. An affordable, reliable, and environmentally sound
supply of electricity is critical to our nation's future.
Conclusion
The ultimate goal for the prototype plant is to show how new
technology can eliminate environmental concerns over the future use of
coal and allow the nation to realize the full potential of its abundant
coal resources to meet our energy needs. Knowledge from FutureGen will
help turn coal from an environmentally challenging energy resource into
an environmentally sustainable energy solution.
Coal is the workhorse of the United States' electric power sector,
supplying more than half the electricity the nation consumes. It is
also the most abundant fossil fuel in the United States with supplies
projected to last 250 years or more. The International Energy Agency
projects a 50 percent increase in worldwide coal use for electricity
generation over the next quarter century.
The fact that coal will be a significant world energy resource
during the 21st century cannot be ignored. Coal is abundant, it is
comparatively inexpensive, and it will be used widely, especially in
the developing world. Global acceptance of the concept of coal-based
systems integrated with sequestration technology is one of the key
goals of FutureGen.
Our challenge is to make sure that when it is used, coal is clean,
safe, and affordable. Technologies that could be future candidates for
testing at the prototype plant could push electric power generating
efficiencies to 60 percent or more--nearly double the efficiencies of
today's conventional coal-burning plants.
Thus, the FutureGen prototype plant would be a stepping stone
toward commercial coal-fired power plants that not only would be
emission-free but also would operate at unprecedented fuel
efficiencies.
This completes my prepared statement. I would be happy to answer
any questions you may have.
Mr. Barton. We now want to hear from Dr. Burke. Your
testimony is in the record. We ask that you summarize it in 7
minutes.
STATEMENT OF FRANK BURKE
Mr. Burke. Good afternoon, Mr. Chairman and members of the
subcommittee. My name is Frank Burke and I am Vice President of
Research and Development for CONSOL Energy, Inc., headquartered
in Pittsburgh. I am appearing here today on behalf of the
National Mining Association and CONSOL to discuss technologies
to meet our Nation's need for clean coal-based electricity.
Mr. Chairman, NMA and I want to thank you, Mr. Boucher, Mr.
Whitfield, Mr. Shimkus, our Pittsburgh representative Mr.
Doyle, and others for your support of coal-based electricity.
The provisions you included in H.R. 6 will, if enacted, help
our Nation to continue to enjoy the benefits of coal in the
future.
Mr. Chairman, there is an inscription on the facade of
Union Station and it says: ``Electricity, carrier of light and
power, devourer of time and space, bearer of human speech over
land and sea, greater servant to man itself unknown.'' This
statement from the 19th century is still true today.
Electricity is produced so reliably that to many people its
source, like oxygen in the air, is unknown and taken for
granted; but electricity is to our modern society and economy
as oxygen is to life. Without electricity, our society would
grind to a halt not within days or hours, but within minutes.
And, Mr. Chairman, coal is solid electricity, because coal
is used to generate more than half of the electricity Americans
need to sustain and enhance our way of life. Coal comprises
over 90 percent of our domestic energy reserve, enough to last
us 250 years, and we can reconcile our need for coal with our
environmental and economic needs through clean coal technology
to preserve our existing coal-based electricity-generating
capacity and to replace and expand it as needed in the future.
First let me commend DOE's coal R&D program and the clean
coal technology program. These have resulted in the development
and widespread commercial use of technologies for the cleaner
and more efficient use of coal that have reduced emissions
while coal use has increased.
Second, the coal-related provisions of H.R. 6 are a further
step in the right direction. The Clean Coal Power Initiative,
provided by this bill authorizing $2 billion through 2012, will
help to ensure that we can bring the products of the R&D
program to commercial readiness. The allocation of funds to
gasification and other technologies in this bill is
appropriate. While the Clean Coal Power Initiative and the
enhanced core coal R&D authorization in H.R. 6 are necessary,
they are not in themselves sufficient to ensure that these
technologies will achieve widespread commercial use.
In this regard, I note that H.R. 6 does not include the
clean coal technology tax incentives included in H.R. 1213,
which are necessary to reduce the technical and financial risk
of deploying these advanced technologies. The Senate Finance
Committee included these incentives in S. 597, and we hope they
will be adopted by the conference committee on the energy bill.
Many of the technical challenges and opportunities for
future coal generation technology are embodied in a clean coal
technology road map developed by the industry and Department of
Energy. This is discussed in more detail in my written
testimony. The road map focuses on the power costs, efficiency
and environmental performance objectives for technologies that
will allow existing plants to meet anticipated future
environmental restrictions such as expected mercury regulation.
The road map lays out the R&D pathway for new gasification
combustion and hybrid technologies for the next generation of
coal-based plants which will be needed for new and replacement
electric capacity. Furthermore, the road map allows us to
determine the cost for the necessary R&D and demonstration
work. We estimate this to be $10 to $14 billion in public and
private funds between now and 2020.
Unfortunately, the Federal funding in the administration's
2004 budget for both the core R&D program and the Clean Coal
Power Initiative demonstration program is low, barely half of
what we need to follow the road map. Without adequate funding
from the public sector, it will not be possible to meet the
road map schedule.
Now let me talk about a new aspect of DOE's program, the
FutureGen project. FutureGen would minimize pollutant emissions
to near zero levels. This facility would be based around the
coal gasification system with the capability to convert coal
gas into hydrogen and to capture and sequester 1 million tons
of carbon dioxide a year.
A recent report from a group called the Energy Future
Coalition and the press coverage it engendered suggested that
CONSOL and others in the industry had accepted the need for
mandatory caps on carbon dioxide emissions. This is not true.
Neither CONSOL nor the NMA believes that global climate change
resulting from carbon emissions is an established scientific
fact, nor do we believe that a mandatory cap on carbon
emissions is justified. However, we do believe that programs
like FutureGen that seek to define the cost and feasibility of
possible technological options are a prudent investment for
industry and the government. Furthermore, FutureGen would serve
as an important research platform to test advanced power plant
components as they emerge from the core R&D program.
It is important to note that FutureGen is not a substitute
for either the core R&D program or the Clean Coal Power
Initiative demonstration program. We need to continue the core
research on new technologies that can be tested at FutureGen
and elsewhere, and we need to continue R&D and demonstration
projects on technologies that are not part of the FutureGen
design.
It is estimated that FutureGen costs will be $1 billion,
with 80 percent provided by the government. The ability of the
government to commit its full 80 percent share of the funding
to the project before major costs are incurred will be critical
to FutureGen's success.
In conclusion, Mr. Chairman, we must continue to define and
follow a technology road map that focuses on the cost,
efficiency and environmental performance of coal-based
electricity-generating technologies to preserve our existing
infrastructure and build new coal based plants. Thank you.
[The prepared statement of Frank Burke follows:]
Prepared Statement of Frank Burke, Vice President, Research and
Development, CONSOL Energy Inc. on Behalf of CONSOL Energy Inc. and The
National Mining Association
Mr. Chairman, my name is Frank P. Burke, and I am vice president of
research and development for CONSOL Energy Inc. (CONSOL). I am
appearing here on behalf of my company as well as the National Mining
Association (NMA) to testify on the current and future technologies
that are needed to assure that the nation has the clean coal-fired
electric generating capacity required to meet our energy demands in the
future.
I would like to commend you Mr. Chairman, for holding these
hearings to discuss the new technologies, and improvements to existing
technologies, which will allow America to continue to use its abundant
coal resources to power our economy. This will be the focus of my
statement to the Committee today: Why America needs coal, why it needs
new technology for the production of electricity from coal, and why a
federal program to support the development of new technology represents
a vital investment in our nation's economic well being. Coal makes up
over 90 percent of our domestic energy reserve. And, coal is
electricity. It is the fuel for over 50 percent of the electricity that
our citizens use to run our businesses and support our everyday lives.
Coal is, and must continue to be, one of the cornerstones of our
nation's energy strategy.
GENERAL INTRODUCTION
CONSOL Inc., founded in 1864, is the largest producer of high-Btu
bituminous coal in the United States, is the largest producer of coal
by underground mining methods, and the largest exporter of U.S. coal.
CONSOL has 23 bituminous coal mining complexes in six states and in
Australia. The company has a substantial technology research program
focused on energy extraction technologies and techniques, coal
combustion, combustion emission abatement and combustion waste
reduction. As you can see from the Appendix, CONSOL has been an active
partner with DOE in the advancement of many technologies and in basic
research. [CONSOL is a publicly held company (NYSE:CNX) with over 6,000
employees].
The NMA represents producers of over 80 percent of America's coal,
the reliable, affordable, domestic fuel used to generate over 50
percent of the electricity used in the nation today. NMA's members also
produce another form of fuel--uranium that is the source of just over
20 percent of our electricity supply. NMA represents companies that
produce metals and non-metals, companies that are amongst the nation's
larger industrial energy consumers. In addition, NMA members include
manufacturers of processing equipment, machinery and supplies,
transporters, and engineering, consulting and financial institutions
serving the mining industry.
ENERGY IN THE UNITED STATES--AND THE NEED FOR A BALANCED ENERGY POLICY
THAT INCLUDES INCENTIVES TO EXPAND THE ELECTRIC GENERATING FLEET
Energy, whether it is from coal, oil, natural gas, uranium, or
renewable sources, is the common denominator that is imperative to
sustain economic growth, improve standards of living and simultaneously
support an expanding population. The significant economic expansion
that has occurred in the United States over the past two decades, and
the global competitiveness of our industry, was in no small measure due
to reliable and affordable energy.
During the summer of 2000 this began to breakdown. Prices of energy
in some regions of the country--especially prices of gasoline, natural
gas and electricity--increased significantly. Spot shortages of
electricity occurred in California and, although the price of energy
receded, the base cause of this problem--too little energy supply
chasing too much energy demand--has not been addressed. Just three
years later, we again see soaring natural gas prices, and the real
possibility of natural gas shortages that may lead to electricity
curtailment. High prices and unreliable energy supplies three years ago
were followed by a slow-down in the economy, and high natural gas
prices now threaten to forestall economic recovery. And, while cause
and effect may not be perfectly correlated, the experiences of the last
several years reinforce the relationship between affordable energy and
economic growth. Enactment of a national energy policy that balances
energy supply with energy demand while simultaneously encouraging
efficiency and greater protection of our environment must be a priority
of the Congress and the Administration to ensure our economic future.
According to the Energy Information Administration, energy use will
increase by an average 1.5 percent per year or by a total of 42 percent
to 139 quadrillion Btu between 2000 and 2025. Consumption of all
sources of energy will increase: petroleum by 47 percent, natural gas
by 49 percent, coal by 30 percent and renewable energy by 46 percent.
An important part of the forecast is the statement that the economy
will become even more dependent upon electricity over the next 20 years
than it is now: Thus, a viable National Energy Policy must include a
strong component to support expansion of our electricity supplies.
THE NEED FOR COAL--COAL IS ELECTRICITY
We learn in grade school that a person needs three things to
survive: food, water and shelter. It is interesting that oxygen is not
added to that list. The omission probably results because oxygen is so
important and so ubiquitous, that we take it for granted. We can live
for days without water, and perhaps weeks without food and shelter, but
for only minutes without oxygen. I bring this up because, in the United
States' economy, electricity is the equivalent of oxygen. Without
electricity, the economy would grind to a halt not in days or week, but
within minutes. Electricity is so ubiquitous, and the electricity
generating industry and its fuel suppliers have made it so reliable,
that to the average consumer, electricity must seem to come, like
oxygen, from the air itself, or perhaps from that socket in the wall.
However, electricity, unlike oxygen, is not a product of nature. It
must be manufactured and delivered, continuously and in ever increasing
amounts. By 2025 we will need 55% more electricity than we generate
today. This can only be accomplished through the creation and
employment of technology, the investment of capital, and the labor of
workers in three fundamental industries: fuel supply, transportation,
and power generation. The industry, which I represent, is responsible,
each year, for producing about 1.1 billion tons of coal a year, almost
1 billion tons of which America uses to keep more than half of its
electricity flowing to homes, hospitals, schools, businesses and
factories. Imagine what would happen to our economy and the well-being
and aspirations of our citizens, if half our electricity were gone
tomorrow. If you understand that, then you understand the importance of
maintaining our existing electricity generating capacity, while
providing for the new capacity necessary to supply the electricity that
America will need to sustain its economic growth in the future.
As we discuss the future need for and cost of developing the clean
coal technologies to upgrade and replace our coal-based generating
capacity, it is important to understand what America's coal miners have
already done to meet the demand of U.S. consumers for low-cost,
reliable electricity. Between 1984, when the Clean Coal Technology
Program was begun, and 2000, coal prices in the United States have been
driven down by 55% in real dollars, because of a doubling in
productivity achieved by America's miners. Had coal prices simply
remained at 1984 levels, the additional direct cost to the U.S. economy
would have been over $100 billion. The coal industry has done this
through the excellence of its work force, development of innovative
mining methods and equipment, and large capital investments in new
technology. Without coal, the indirect cost, in terms of the impact of
higher electricity prices on the domestic economy, would have been
much, much greater
Today, more than one-half of U.S. electricity is generated from
abundant, low cost, domestic coal. And, coal can play a greater role in
meeting future demands, because it constitutes more than 90 percent of
the United States' fossil fuel resources, enough to last more than 250
years at current consumption rates. What is needed now is the
development and, more importantly, the commercial use of Clean Coal
Technologies to take full advantage of the energy resource that
American's coal miners are prepared to deliver.
THE NEED FOR CLEAN COAL TECHNOLOGIES
The analogy between electricity and oxygen is appropriate for
another reason. One of the principal reasons for developing new coal-
fired generating technologies is to ensure that electricity generation
from coal does not compromise the quality of the air we breathe.
Because of its chemical composition, coal poses more environmental
concerns than other fossil fuels. On average, coal contains more sulfur
and nitrogen, and more mineral matter, than oil or natural gas.
Fortunately, the means are available to control the emission of these
substances into the environment to levels that meet current regulatory
limits. A wide range of technologies is already deployed on many coal-
fired power stations to control emissions of these pollutants. These
include particulate collection devices, such as electrostatic
precipitators and fabric filters that control emissions of coal ash,
flue gas desulfurization scrubbers of various designs that control
emissions of sulfur dioxide (SO2) and a variety of methods
and devices for reducing nitrogen oxide (NOX) emissions.
There are no commercially available methods to control emissions of
mercury or carbon dioxide from coal-fired power plants, but as I will
discuss, these are the subject of active research programs.
Like those throughout the world, the United States faces the
challenge of meeting our need for low cost energy while reducing the
environmental impact of energy production and use. The federal and
state governments are likely to impose new environmental regulations
that will reduce SO2, NOX, and mercury emissions
from existing power plants to levels well below current regulatory
limits. This will require the widespread deployment of improved
technology that further reduces SO2 and NOX
emissions below current regulatory levels at an acceptable cost.
Mercury will be substantially reduced as a co-benefit of this, and, in
the long run, it may be necessary to develop and deploy technology to
further limit mercury. In addition, there are opportunities to improve
the efficiency of existing generating units. Increasing efficiency can
reduce emissions, because less fuel is required for each unit of
electricity generated, and efficiency improvement is the only method
currently available to reduce CO2 emissions from power
production.
A recent report by the Energy Future Coalition, and particularly, a
number of misleading press releases and news stories engendered by it,
imply that members of the coal industry, including CONSOL, have
endorsed the need for mandatory carbon emission reductions. This is not
true, and I would encourage you to read the section of the report
written by the coal-working group, which was the only part of the
report in which CONSOL and others in the coal industry participated.
The coal working group section frames the debate on this issue, but it
makes assertions or recommendations regarding the need for carbon
emission reductions. Neither CONSOL nor the NMA believes that climate
change resulting from carbon emissions is an established scientific
fact. On the contrary, many credible scientists have presented strong
arguments to rebut such claims. We strongly oppose imposition of a
carbon tax or mandatory limit on carbon emissions. Nevertheless, we
encourage the development and deployment of technology to increase
power plant efficiency, where it makes economic sense, with the
concomitant result of decreasing carbon emissions. We also support
research to explore other technological options for greenhouse gas
management within the DOE coal research program, because we as a nation
need to know their cost and technical feasibility, to inform public
policy decisions-makers and as a prudent investment in preparing a
technological response so that we can continue to enjoy the benefits of
coal-fueled electricity should public policy ever require carbon
emission reductions.
These Clean Coal systems will need to be designed and integrated in
a way that achieves the expected benefits of each, without creating any
unintended consequences. For example, the use of combustion
modifications to reduce NOX emissions can result in
increased carbon in coal flyash, making flyash less valuable as a
byproduct. Selective Catalytic Reduction, which is an effective means
for NOX control, can cause deposition that impairs
efficiency in the boiler system. On the other hand, the intelligent
integration of technologies can have synergistic benefits. As noted
earlier, emission control devices installed for other pollutants can
remove mercury from the flue gas at no additional cost. As another
example, the solid byproducts from coal combustion can be converted
into salable materials such as wallboard gypsum and road aggregates.
Research is underway to learn how to take full advantage of co-benefits
such as these, and to incorporate them into the design of existing and
new power plants.
In the future, we will need new coal-fired power plants to meet
electricity demand growth and to replace existing facilities as they
reach the end of their economic lives. Notable among these new
technologies are supercritical pulverized coal combustion, advanced
combustion, integrated gasification combined cycle (IGCC), and various
hybrid power systems. These technologies hold the promise of high-
energy efficiency and minimal environmental impact if they are
developed and successfully deployed at an acceptable cost. For example,
IGCC technology is currently being demonstrated at several sites, but
it must still be considered pre-commercial technology because of its
relatively high capital cost. Nevertheless, IGCC systems produce the
cleanest power available from coal; emissions from these systems
approach the levels generated by modern natural gas-fired power plants,
and research is underway to reduce the capital cost through design
improvements. As with all technologies, the full benefits of potential
design optimization will not be gained until a sufficient number of
full-scale commercial units have been built and operated.
COAL CHARACTERISTICS AND REGIONAL DIFFERENCES
Furthermore, we need to be sure that there are Clean Coal
Technologies, which work well with all coals. Coals differ in the
geological characteristics of the reserves, which affects the choice of
mining method, and hence the cost of production. The geographic
location of the reserve affects its economic availability to specific
power plant markets. It is important that Clean Coal technology users
have the flexibility to select coals that meet their technical
specifications and economic requirements. New Clean Coal Technologies
must be developed that can accommodate, or be modified to accommodate,
a wide range of coals while achieving high efficiency and excellent
environmental performance. Achieving fuel flexibility must be a key
objective in designing the Clean Coal Technology development and
commercialization plan.
This issue arises because coal is a highly variable geologic
material, and differences in individual coal types affect their
performances in electricity generating units. Individual coals differ
on the basis of energy content, sulfur content, ash composition, and
other properties. U.S utility coals can be categorized into three
groups:
1. Bituminous coals are mined throughout the U.S. They have medium to
high-energy contents. Bituminous coals from different regions
differ greatly in sulfur content and mineral matter
composition.
2. Subbituminous coals are mined in the western U.S., principally
Wyoming and Montana. They are characterized by low sulfur and
low energy content.
3. Lignite coal is mined in Texas, Louisiana, and North Dakota. Lignite
has the lowest energy content of U.S. coals (less than 8,300
Btu/lb), and low to medium sulfur content.
Mercury concentrations are variable across the coal regions, but
tend to be somewhat lower for the subbituminous coals and somewhat
higher for the lignites (on an equivalent energy-content basis). Other
important coal-quality parameters, such as mineral matter composition,
chlorine content, alkali content, and grindability, vary both across
and within the above groupings.
THE ROLE OF THE FEDERAL GOVERNMENT IN TECHNOLOGY DEVELOPMENT
The DOE Office of Fossil Energy, through its Coal and Environmental
Systems program, expends about $200 million/year to co-fund coal-
related R&D, in addition to the current Clean Coal Power Initiative
demonstration program. The DOE is supporting the development of new
technology for mercury reduction and carbon management. The DOE coal
program also includes the Vision 21 R&D program, which seeks to develop
advanced, highly efficient, low-emitting energy complexes, for the
production of electricity, fuels and chemicals. The federal government
has had a significant role in the development of clean coal technology.
The original Clean Coal Technology (CCT) program and the current Clean
Coal Power Initiative support the first-of-a-kind demonstrations of new
coal use technologies. These demonstrations encompass a wide range of
technologies, including environmental controls, new power generating
facilities and fuel processing. Forty projects were conducted in the
original CCT program, with a total value of $5.4 billion, consisting of
$1.8 billion in federal funds and $3.4 billion in non-federal funds (a
2/1 leverage on federal dollars).
In January of this year, the Energy Department announced the
selection of eight projects to receive $316 million in funding under
Round 1 of the Clean Coal Power Initiative program, the first in a
series of competitions to be run by the Energy Department to implement
President Bush's 10-year, $2 billion commitment to clean coal
technology. Private sector participants for these projects have offered
to contribute over $1 billion, well in excess of the department's
requirement for 50 percent private sector cost-sharing.
Three of the projects are directed at new ways to comply with the
President's Clear Skies initiative which calls for dramatic reductions
in air pollutants from power plants over the next decade-and-a-half.
Three other projects are expected to contribute to President Bush's
voluntary Climate Change initiative to reduce greenhouse gases. Two of
the projects will reduce carbon dioxide by boosting the fuel use
efficiency of power plants. The third project will demonstrate a
potential alternative to conventional Portland cement manufacturing, a
large emitter of carbon dioxide.
The remaining two projects will reduce air pollution through coal
gasification and multi-pollutant control systems.
CONSOL has been an active participant in coal-use research since
the 1940s. Our goals are closely aligned with those of the DOE coal
program, and much of our research has been done in partnership with the
DOE (see Appendix). We were a member of the project teams for two of
the CCT projects, and we made both financial and technical
contributions to these projects. We also were selected for award under
the recent Power Plant Improvement Initiative program to demonstrate a
multi-pollutant control technology, targeted at the smaller power
plants that generate about one-fourth of our coal-based electricity.
Much of our research is directed at helping our customers deal with
the consequences of environmental regulations. For example, we
developed a new technology for the beneficial use of the solid
byproduct of flue gas desulfurization, by converting it into aggregates
for use in road and masonry construction. This technology, which we
piloted in partnership with DOE, reduces the cost and the land-use
consequences of solid waste disposal. It can provide a valuable source
of construction materials in areas without good indigenous sources,
such as Florida, and areas of high growth, such as the southwestern
states. Projects like this, which are a win for the economy and a win
for the environment, justify CONSOL's commitment to work in partnership
with the DOE to develop technology that makes sense from both
perspectives.
In some cases, research and demonstration projects, such as those
conducted under the DOE Coal and CCT programs, have been sufficient to
bring important technologies directly to the marketplace. For example,
over $1 billion in Low-NOX burners have been installed at
U.S. power plants since being demonstrated in the CCT program. However,
other CCT program technologies, such as Integrated Gasification
Combined Cycle systems, have not been commercialized at their current
stage of development because of the technical and economic risk that
remains despite these one-of-a-kind demonstrations. Nevertheless, large
scale demonstrations are essential to understand the technical and
economic performance of these new technologies and to provide potential
owners and inventors with sufficient confidence to be able to attract
financing.
The DOE is now preparing to issue a second CCPI solicitation. We
believe that these large-scale demonstration projects are essential to
reduce the technical and economic risks of new advanced clean coal
technology. Technology demonstrations are an integral part of the Clean
Coal Technology Roadmap, as discussed below.
THE CLEAN COAL TECHNOLOGY ROADMAP
The term ``Clean Coal Technology'' (CCT) is used to describe
systems for the generation of electricity, and in some cases, fuels and
chemicals from coal, while minimizing environmental emissions. This is
accomplished through increased efficiency (i.e., electricity produced
per unit of fuel [energy] input), equipment for reducing or capturing
potential emissions, or a combination of the two. Various CCTs are
commercially available, or have been demonstrated at full commercial
scale, but need further commercial use for economic optimization. Other
CCTs are in the research and development stage.
Currently available CCTs include the efficient pulverized-coal-
fired boiler (supercritical type) equipped with a full complement of
fully-developed, state-of-the-art pollution control technologies. An
example of this would be a supercritical boiler equipped with selective
catalytic reduction for NOX, high efficiency flue gas
desulfurization for SO2, and a particulate collection
device. It is important to realize that many coal-fired generating
units are currently equipped with these CCT systems, some of which were
brought to the state of commercial readiness since 1986 in the
Department of Energy's previous Clean Coal Technology program.
Clean Coal Technology also refers to high-performance technologies
that are well along the development path, but not yet fully
demonstrated to be commercially available because of either technical
or economic risks. Examples of these are integrated gasification
combined cycle (IGCC) and advanced combustion power plant technologies.
``Advanced'' Clean Coal Technology refers to technology concepts
that are in development for future use, such as advanced IGCC or
ultrasupercritical boiler technology. In this context, the term
``advanced'' refers to improvements in costs, efficiency, and
performance that are expected at some future date, assuming successful
development.
Moving advanced clean coal technologies to full commercial
operation will take a continuing commitment to research, development,
demonstration and a strategy to ensure that the technologies, once
developed, will be deployed commercially. To provide a means of
planning future research needs, and to chart progress toward meeting
them, the industry, largely through the efforts of the Coal Utilization
Research Council, the EPRI, and the Department of Energy, has devised a
Clean Coal Technology roadmap that sets cost and performance targets
and a timeline (See Tables, below) for new coal technology. It must be
clearly understood that these are merely research targets and are not
intended to serve as a basis for regulatory requirements. Moreover, as
noted later, progress along the roadmap will depend upon adequate
funding. If the roadmap were followed, technology would be available in
the near term to allow operators of existing coal-fueled power plants
to meet increasingly stringent environmental regulations, such as those
of the Clear Skies Act. Again, were the roadmap followed, it would be
possible in 2015 to design a high efficiency power plant, capable of
carbon capture, with near-zero emissions; by 2020, the first commercial
plants of this design would be built.
DOE/CURC/EPRI CCT Roadmap I
----------------------------------------------------------------------------------------------------------------
Reference
Roadmap Performance Targets Plant* 2010 2020
----------------------------------------------------------------------------------------------------------------
SO2, % Removal.................................................. 98% 99% >99%
NOX, lb/MMBtu................................................... 0.15 0.05 <0.01
Particulate Matter, lb/MMBtu.................................... 0.01 0.005 0.002
Mercury......................................................... ``Co- 90% 95%
benefits''
By-Product Utilization.......................................... 30% 50% ~100%
----------------------------------------------------------------------------------------------------------------
*Reference plant has performance typical of today's technology. Improved performance achievable with cost/
efficiency tradeoffs.
DOE/CURC/EPRI CCT Roadmap II
----------------------------------------------------------------------------------------------------------------
Reference
Roadmap Performance Targets Plant* 2010 2020
----------------------------------------------------------------------------------------------------------------
Plant Efficiency (%,HHV)........................................ 40 45-50 50-60
Availability, %................................................. >80 >85 ~90
Capital Cost, $.VkW............................................. 1000-1300 900-1000 800-900
Cost of Electricity, $/MWh...................................... 35 30-32 <30
----------------------------------------------------------------------------------------------------------------
*Reference plant has performance typical of today's technology. Improved performance achievable with cost/
efficiency tradeoffs. W/o carbon capture and sequestration.
The roadmap contains considerable detail on the specific
technological advances that are necessary to meet the roadmap coal.
Some of these ``critical technologies'' are listed below.
Improvements for Existing Plants
Mercury control
Low-NOX combustion at reduced costs
Fine particle control
By-product utilization
Advanced Combustion
Ultra-supercritical steam
Oxygen combustion
Advanced concepts (e.g., oxygen ``carriers'')
Gasification Systems
Gasifier advances and new designs (e.g., transport gasifier)
Oxygen separation membrane
Syngas purification (cleaning) and separation (e.g., hydrogen,
CO2)
Energy Conversion
Advanced gas turbine technology using H2-rich syngas
Fuel cell systems using syngas
Fuels and chemicals
Carbon Management
CO2 capture and sequestration
<10% increase in cost of electricity for >90% removal of
CO2 (including sequestration)
``Hydrogen economy''
Systems Integration
Integrated power plant modeling and virtual simulation
Sensors and smart-plant process control
Finally, the roadmap makes it possible to estimate the cost of the
research, development and demonstration programs necessary to achieve
the performance targets, as shown in the table below. These values
represent the total cost of the research programs, including both
federal funds and private sector cost shares.
------------------------------------------------------------------------
RD&D Spending
Coal Technology Platforms Through 2020
(Billion)
------------------------------------------------------------------------
IGCC/Gasification....................................... $3.5
Advanced Combustion Systems............................. $1.7
Innovations for Existing Plants......................... $1.4
Carbon Capture/Sequestration............................ $2.3 (?)
Coal Derived Fuels and Liquids.......................... $1.2
Total................................................... $10.1
------------------------------------------------------------------------
The cost for carbon capture and sequestration research is shown
with a question mark, to denote the relatively greater uncertainty in
the estimate of the cost of research in this unprecedented area. It
could be substantially higher, particularly because a number of large
scale, long-term demonstrations will be needed to understand the
technical, economic and environmental feasibility of carbon
sequestration technology. This was one conclusion of a recent National
Coal Council report, entitled ``Coal-Related Greenhouse Gas Management
Issues,'' which provides a detailed discussion of the opportunities and
impediments to developing, demonstrating and implementing greenhouse
gas management options related to coal production and use.
Unfortunately, current funding levels are not sufficient to meet
the roadmap goals. The table below compares the funding levels required
to follow the roadmap to the level in the Administration's FY 2004
budget.
(all figures in $ millions)
----------------------------------------------------------------------------------------------------------------
Administration
Technology Program FY 2004 CURC Roadmap Annual R&D
Request Budget\1\
----------------------------------------------------------------------------------------------------------------
IGCC/Gasification.................................................. 51.0 125.0
Advanced Combustion................................................ 0.0 42.0
Advanced Turbines.................................................. 13 16.5 (for syngas from coal)
Innovations for Existing Plants.................................... 22.0 43.0
Carbon Sequestration............................................... 62.0 30.0
Advanced Research
Advanced Materials Only.......................................... 4.65 4.0
Coal Derived Fuels & Liquids....................................... 5.0 12.8
Total R&D........................................................ 157.7 273.3
Clean Coal Power Initiative........................................ 130.0 240.0
TOTAL............................................................ 287.7 513.3
----------------------------------------------------------------------------------------------------------------
\1\This number is 80% of the total R&D amount required and represents the federal contribution.
Although it varies by program area, the overall R&D funding level
is little more than half of that called for in the CURC roadmap.
Unfortunately, this continues a pattern of past years of underfunding
clean coal research. Unless research and demonstration funds are
increased, it is unlikely that technology will be developed on the
roadmap schedule, if at all.
Similarly the funding level for the CCPI falls well below the
roadmap requirements. Furthermore, the progress of the CCPI program is
hampered by the requirement for annual, as opposed to advance
appropriations. Because of the necessary size and cost of demonstration
projects, it was necessary for the DOE to take money from both FY02 and
FY03 appropriations to be able to fund the first solicitation. Future
CCPI solicitations are likely to be delayed or limited in scope for the
same reason. It is even possible that some necessary demonstrations
will not be done because the available appropriations are insufficient.
Given this situation, it may be appropriate for the Department to
consider targeted solicitations focused on the roadmap objectives, or
to utilize other approaches to match demonstration priorities with
budgetary limitations.
THE FUTUREGEN PROJECT
On February 27 of this year, the Department of Energy announced
plans to build a prototype of a coal-based power plant of the future.
Dubbed ``FutureGen,'' this facility would be based around a 275MW IGCC
system, but it would have the capability to convert synthesis gas into
hydrogen and to capture and sequester up to one million tons per year
of carbon dioxide. FutureGen would be designed to minimize emissions of
criteria pollutants and mercury to ``near zero'' levels. Furthermore,
the FutureGen facility would be designed to serve as a ``research
platform'' capable of testing advanced components, such as air
separation membranes or fuel cells, during the ten year duration of the
project, and perhaps beyond. The Department issued a ``Request For
Information'' with a closing date of June 16, 2003, soliciting
responses from parties willing to undertake the FutureGen project. My
company, CONSOL Energy Inc., is a member of a ten-company group of
major U.S. coal producers and users, which submitted a response to the
DOE RFI, offering to enter into negotiations to conduct the FutureGen
project. In part, our submittal says that the FutureGen mission should
have four key elements:
1) develop commercially competitive and affordable coal-based
electricity and hydrogen production systems that have near-zero
emissions
2) develop large-scale CO2 sequestration technologies that
are technically and economically viable and publicly acceptable
3) provide a large-scale research platform for the development and
commercialization of advanced technology
4) provide opportunity for stakeholder involvement and education
The vision of FutureGen as a research platform is particularly
significant because it means that the FutureGen facility can be used as
a test site to bring promising technologies out of the core R&D program
and to accelerate their testing at scales up to full commercial
implementation without the need for separate stand-alone test
facilities. However, it is important to understand that FutureGen
should not be viewed as a substitute for either the core R&D program or
the CCPI demonstration program for at least two reasons: First, the
FutureGen facility will not be operating for at least five years.
During that time we need to continue the research needed to bring new
technologies to the state that they can be tested at FutureGen. Second,
we need to continue R&D on technologies, such as combustion-based
systems, that are not part of the FutureGen design. That said, as the
FutureGen concept is further defined, industry and government should
look for opportunities for efficiencies in the coordination of the R&D
program, the CCPI, and FutureGen to produce the greatest benefits at
the lowest possible cost. This coordination should be an integral part
of the ongoing technology road-mapping process.
Finally, although the exact cost is not known, DOE has estimated
the project cost as $1 billion, with 80% provided by the federal
government, and 20%, or $200 million, provided by the industrial
alliance and its partners. Both the 80/20 cost share ratio and the
ability of the Government to commit its full cost share to the project
before major costs are incurred are critical to the project's success.
INCENTIVES FOR CLEAN COAL TECHNOLOGY DEPLOYMENT
The foregoing discussion in this statement deals with the need for
research, development and demonstration of advanced clean coal
technology, and discusses technical and economic criteria that these
new technologies will need to meet to achieve acceptance in the
commercial marketplace. However, while the Clean Coal Power Initiative
and the enhanced core Fossil Energy authorization in Sections 21501 and
21511 of H.R. 6 are necessary for the continued development of coal
technology, they are not by themselves sufficient to ensure that these
technologies will find their way into widespread commercial use. When
they are initially introduced, they will need to be built with
substantial engineering contingencies, to assure their operability and
reliability, which will increase capital and operating costs. Over
time, as operating experience is gained, these costs will come down.
Therefore, there is a need for financial incentives to offset the
increased technical and financial risk inherent in the initial
deployments of advanced clean coal technologies, In this regard I note
that H.R. 6 does not include the tax incentives for a limited number of
commercial demonstrations of advanced clean coal technologies that were
included in H.R. 1213, the ``Clean Coal Power Act of 2003.'' These
incentives are included in S. 597, the ``Energy Tax Incentive Act of
2003, reported by the Senate Finance Committee, and we hope that they
will be adopted by the Conference Committee on the Energy Bill.
CONCLUSIONS
Mr. Chairman, there is little doubt that coal will continue to be
used in the United States and abroad as a principal fuel for
electricity generation, and coal's use will grow over time. The
interests of the economy, society, and the environment in coal can be
reconciled if we invest now in the development and deployment of
advanced clean coal technology. By working with industry to develop a
coal technology development roadmap, the Department of Energy has and
continues to align its program with a logical path forward to support
the development of advanced clean coal technology. The coal industry
remains committed to do our part to see that coal remains an abundant,
affordable fuel for power generation, and to help to advance the
technology roadmap to achieve its goals of societal, economic and
environmental betterment.
Mr. Barton. Thank you, Dr. Burke.
We now want to hear from Mr. Courtright on behalf of EPRI.
Your statement is in the record and we ask that you summarize
it in 7 minutes.
STATEMENT OF HENRY A. COURTRIGHT
Mr. Courtright. Thank you, Mr. Chairman and members of the
committee. To sustain a strong energy infrastructure and
resolve the energy environmental conflict, we recommend to the
committee that two challenges be solved.
The first challenge, which you have discussed, is to
strengthen the portfolio of generation options for the future,
using a diverse base of many energy sources including fossil
fuels, hydro, nuclear and renewable energy, and to adequately
address fuel supply uncertainty and energy security in our
Nation. Coal provides over half the electricity, as said
before. By keeping coal in the mix will ensure not only that
this mix will apply but will lower energy costs to the
consumer. In a study published in 2002 by EPRI, we estimated
that consumer benefits of keeping coal in the mix are enormous,
between $300 billion and $1.3 trillion to consumers.
The second challenge is that economical technologies for
sequestering CO2 need to be developed if fossil
fuels are to remain as environmentally acceptable, affordable
energy sources for electricity production. EPRI, DOE, and the
Coal Utilization Research Council have developed a common clean
coal technology road map which includes two pathways to keep
coal as a viable option and allow for the reduction for
CO2.
The first pathway involves coal gasification, using either
integrated gasification combined cycle, IGCC, or hybrid
coproduction systems that use fuel cells in addition to provide
electricity and transportation fuels too. A possible new
application of these technologies will be the FutureGen
project.
The second pathway involves advanced combustion of
pulverized coal that promises lower emissions, higher
efficiency and fewer CO2 emissions. I provide
information on advanced combustion in my written statement, but
I will focus my comments today on IGCC and CO2
capture.
IGCC is currently the cleanest coal technology available
and has been demonstrated at four plants that are currently
operating: two in the U.S. and two in Europe. The economics of
IGCC have been evaluated in several EPRI studies, with the
following observations. The capital costs of IGCC will be
slightly higher than pulverized coal, but will provide a cost
of electricity very similar to the technology. If we compare
IGCC through a natural gas combined cycle plant and we assume
that natural gas long-term prices will be above $4 per million
BTU, as they are now, the IGCC plant would provide the lower
cost of electricity.
These studies also show the advantage for IGCC if
CO2 removal is required. When you look at today's
known technologies and you put on the cost of CO2
capture, transportation, storage even on IGCC, the cost of
electricity goes up 30 to 40 percent. However, if you compare
that to CO2 sequestration for a conventional coal
plant today, that would add 70 to 80 percent to the cost of
electricity.
So the successful future of IGCC as we see it requires
three things:
First, that financial institutional confidence be
established in this new power technology. Financing firms are
unfamiliar with this technology in most cases. We need
incentives; and energy legislation should support the need for
early deployment of IGCC.
We need increases in the overall system reliability of IGCC
for power production operations and to document those so energy
companies become confident in the use of this technology as a
viable alternative in competitive marketplaces.
And third, we need further reductions in the costs of
electricity produced, especially with the cost of
CO2 capture.
This research and development can be supported in the
FutureGen project and the Clean Coal Power Initiative projects.
It is important that we sustain sufficient funding levels for
these projects over the next decade for the resolution of this
pacing issue of CO2 capture costs. Coproduction, as
said by others, have the efficiency of the cycles could be as
high as 60 percent. This efficiency, coupled with
CO2 capture and sequestration, would result in
significant reduction of CO2. We need to keep
sufficient funding of these new hybrid cycles to move them to
their commercial State.
CO2 sequestration. The development of
CO2 capture, transportation, storage technologies,
is critical to sustaining coal as an option, assuming C02
emissions will be limited in the future. At present there is no
technology that is commercially available for economic capture
and disposal of CO2 from power plants. Processes
used in other industries for CO2 capture, if applied
to today's conventional power plants, would nearly double the
costs of electricity. Because of the low power cost value of
over 300,000 megawatts of existing coal plants, there is an
incentive for an R&D program to investigate cost reductions for
CO2 capture from pulverized coal plants. As
mentioned earlier even for advanced systems such as IGCC adding
CO2 sequestration with the technologies we know now
would increase the cost of electricity by about 30 to 40
percent. We must focus on reducing the cost and energy penalty
associated with the capture of CO2. We think this is
a very high priority. The FutureGen project will help prove the
long-term safety and effectiveness of CO2 storage.
However, FutureGen by itself is not sufficient to prove
storage and all applications. As stated in a recent National
Coal Council report, and I quote: Given the number of possible
sinks and likely regional differences in the characteristics of
these sinks, there is a need for several of these large-scale,
long-duration demonstrations. The challenge of funding is even
made more difficult since the ongoing DOE R&D program and coal
and CO2 supports these long-term goals, too.
Therefore, it would be counterproductive to cut any ongoing
coal and CO2 research programs in order to fund
FutureGen and other large demos. We need to meet these
challenges by funding both ongoing coal R&D programs and new
programs of large-scale testing.
In summary, we must sustain a diverse energy portfolio by
keeping coal predominantly in the mix through advanced systems
like IGCC, coproduction and advanced combustion. And we must
accelerate the research and development of efficient and
environmentally sound carbon capture and storage technologies.
Thank you for the opportunity to address the committee, and
I welcome your questions.
[The prepared statement of Henry A. Courtright follows:]
Prepared Statement of Henry A. Courtright, Vice President, Power
Generation and Distributed Resources, EPRI
Mr. Chairman and Members of the Committee: I represent EPRI, which
is a non-profit, collaborative organization conducting electricity
related R&D in the public interest. EPRI has been supported voluntarily
since our founding in 1973. Our members, public and private, account
for more than 90% of the kilowatt-hours sold in the U.S., and we now
serve more than 1000 energy and governmental organizations in more that
40 countries.
My testimony will focus on the technology pathways needed for the
continued use of coal for power generation in the United States. EPRI
has used a roadmapping process, in conjunction with more than 200
organizations; representing electric utilities, government, industry
and academia; to address the fundamental societal concerns of the 21st
century. This work identified several ``destinations'' to be achieved
to increase electricity's benefits to society over the next 50 years
through advances in science and technology. One of these destinations
is to ``resolve the energy/environment conflict'' with particular
emphasis on carbon management. In order to resolve this conflict there
are two limiting challenges that must be solved:
1. Strengthen the Portfolio of Electricity Generation Options
2. Accelerate Development of Carbon Sequestration Technologies
The electricity generation portfolio should consist of a broad
range of energy sources, including fossil, hydro, nuclear and renewable
energy to adequately address issues of fuel supply uncertainty, price
volatility, energy security and global sustainability. Distributed
energy resource technologies are also needed to enhance power system
flexibility and reliability-based generation. Coal provides over half
of America's electricity and keeping coal in the generation portfolio
will assure the diversity of domestic supply options and will moderate
the energy cost impact on the consumer. In a study published in May
2002, EPRI estimated that the consumer benefits of keeping coal in the
mix through a strong research and development (R&D) program are
enormous, between $300-$1,300 billion 1 (in 2000 dollars).
The range of values reflects different assumptions about natural gas
prices and discount rates used to determine net present values. If
recent gas price levels continue into the future then the high end of
the range, or greater than $1.0 trillion, is an appropriate benefit
value.
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\1\ Market-based Valuation of Coal Generation and Coal R&D in the
U.S. Electric Sector, EPRI, Palo Alto, CA and LCG Consulting, Los
Altos, CA : 2002 1006954
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Economical technologies for sequestering carbon dioxide
(CO2) need to be developed if fossil fuels are to remain as
environmentally acceptable, affordable energy sources for electricity
production. These technologies must include both direct methods such as
capturing CO2 from electricity generation processes and
storing it in geological formations, as well as indirect methods such
as managing forests.
Technology Pathways for Coal Use in Power Generation
EPRI, DOE's Fossil Energy Office and the National Energy Technology
Laboratory, (NETL) and the Coal Utilization Research Council
2 (CURC) have recently compared their individual studies and
collaborated to develop a common ``Clean Coal Technology Roadmap'' that
provides performance targets, critical technology needs, development
costs and benefits to society. This joint roadmap provides guidance to
energy companies, equipment manufacturers and government on public/
private R&D that is essential to achieve the coal performance targets.
Each of the major pathways allow for reduction of CO2
intensity of generation. The clean coal roadmap identifies two key
technology pathways that can keep coal as a viable generation option.
These include:
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\2\ The CURC is a group of electric utilities, coal producers,
equipment suppliers, state government agencies, and universities. CURC
members work together to promote coal utilization research and
development and to commercialize new coal technologies. Its 40+ members
share a common vision of the strategic importance for this country's
continued utilization of coal in a cost-effective and environmentally
acceptable manner.
Coal Gasification
Power Generation with extremely low emissions via
Integrated Gasification Combined Cycle (IGCC)
Co-Production of transportation fuels (such as hydrogen)
with electricity generation using combined cycles and fuel
cells. One example of this technology is the recently
announced FutureGen Presidential initiative to create power
and hydrogen in conjunction with CO2 capture and
storage.
Advanced Combustion
A number of advanced pulverized coal (PC) combustion
options also promise extremely low emissions of criteria
pollutants combined with higher efficiency of generation
thus producing fewer CO2 emissions per kilowatt
of generation. Some of these options concentrate the
streams of CO2 to enhance its capture.
Integrated Gasification Combined Cycle (IGCC)
IGCC involves the gasification of coal with the resulting syngas
being fired in a gas turbine. The hot exhaust from the gas turbine
passes to a heat recovery steam generator (HRSG) where it produces
steam that drives a steam turbine. Power is generated from both the gas
and steam turbines, resulting in a combined cycle with higher
efficiency. IGCC using coal for power generation is currently the
cleanest coal technology available and is being demonstrated at four
plants that are currently operating, two in the U.S. and two in Europe.
IGCC technologies control most of the pollutants as part of the
conversion process, rather than the use of ``backend'' clean-up devices
added to today's plants.
The economics of the coal utilization technologies are continuously
being evaluated in EPRI studies, with the following observations:
Currently the capital cost of IGCC is estimated to be a
slightly higher than for Pulverized Coal (PC) plants but the
cost of electricity (COE) from the two technologies is very
similar. However, because of the limited experience with IGCC
the risk-driven financing costs for IGCC may be higher
initially.
The difference in the cost of electricity (COE) for an IGCC
versus a natural gas combined cycle plant (NGCC) is highly
dependent on fuel costs. A NGCC plant with natural gas at
$2.50/Million Btu has a slight advantage over IGCC with coal at
$1.50/Million Btu. But with long-term natural gas prices
expected to be above $4.00/Million Btu, the IGCC plant will
provide the lower cost of electricity.
When the costs of CO2 capture using currently
available technologies are evaluated for the various
technologies, the costs for pre-combustion CO2
removal from the syngas in IGCC are much lower than for post-
combustion CO2 capture from the large volumes of
flue gases from PC or NGCC plants. The increase in COE for
CO2 capture is 25-30% for IGCC but 60-70% for PC.
When the costs of CO2 transportation and
sequestration are also added, the COE increases are 30-40% and
70-80% respectively for IGCC and PC. These study results show
the advantage for IGCC if CO2 removal is required.
The successful future of IGCC requires:
Financial institution confidence must be established in this
``new'' power generation technology. Incentives in energy
legislation should support the need for early deployment of
this key technology.
Further reductions in capital costs to reduce the cost of
electricity produced. Research and development programs are
needed to enhance the performance and reduce the cost of
CO2 capture technologies, together with
demonstration of CO2 sequestration alternatives, as
envisaged in the proposed DOE FutureGen Project. DOE's Clean
Coal Power Initiative projects can also provide some of this
important R&D. Sustaining sufficient funding levels over the
next decade is critical for resolution of this pacing issue.
Increase in overall system reliability and availability of
IGCC for power production operations. The use of two-train
gasification systems that provide appropriate sparing for
higher availability levels of electricity production would
initially solve this concern although at increased capital
cost.
Co-Production/Hybrid Cycles
Providing hydrogen for power and transportation from domestic
primary energy sources, such as coal, will reduce dependency on
imported energy and enhance national security.The development of
advanced coal-based cycles, with near-zero emission capability, is an
important long-term objective of the coal roadmap. These concepts are
contained in the Clean Coal Technology Roadmap, DOE's Vision 21 effort
and in the FutureGen initiative. These cycles may include the following
capabilities:
Gasification of coal
Syngas firing with advanced turbines
Hydrogen-fired turbines
Hydrogen powered fuel cells
Production of chemicals or liquid fuels for transportation
Capture of CO2 for sequestration
The efficiencies of these advanced cycles could reach or exceed 60%
(Lower Heating Value or LHV). This high efficiency, coupled with
CO2 capture and sequestration would result in significant
reduction of CO2 compared to existing technologies for coal-
based generation technologies.
The provision of sufficient funding, through both government
programs and public/private partnerships, is needed throughout this
decade and into the next decade to accelerate the development of these
cycles to their commercial state and provide clean coal options for a
new fleet of coal-based electricity generation plants.
Advanced Combustion
Higher efficiency in combustion and steam cycles is important to
the reduction of all forms of emissions. Efficiency improvement is the
most cost-effective approach for reducing CO2 emissions
until CO2 capture and storage becomes a commercially
available technology and process. Opportunities for efficiency
improvements in coal-fired power plants include:
Improved Materials for Boilers and Turbines--the development
of materials to enable the move from supercritical steam cycles
to higher temperature and pressure ``ultrasupercritical''
conditions can result in efficiencies up to 50% (LHV) for
bituminous PC power plants, or an efficiency increase of 5-7
percentage points from conventional plants. A DOE/NETL funded
project involving U.S. boiler manufacturers, EPRI and the Ohio
Coal Development Office has been launched to provide materials
for higher efficiency operation. Application of this material
technology is expected to be available within a decade.
Innovative Combustion Technologies--as mentioned earlier, the
capture of CO2 from the flue gases of PC plants with
existing technology is very costly and energy intensive.
Because of the importance of the 320 GW of existing coal plants
in retaining low power costs there is an incentive for an RD&D
program to investigate possible reductions in the costs and
energy consumption for CO2 capture from PC plant
flue gases. It is also important to examine innovative
combustion technologies such as combustion with oxygen and
recycled CO2 (Oxyfuel).
CO2 Sequestration
The development of CO2 capture, transport and storage
technologies/processes is critical to sustaining coal as an option of
power generation. The development of technologies for more efficient
conversion of coal to electricity must be matched with a vastly
expanded CO2 sequestration R&D program.
No technology is at present commercially available for capturing
and disposing of CO2 from power plants. Processes used in
other industries for CO2 capture, if applied to existing
coal-fired plants would nearly double the cost of electricity.
CO2 capture and storage for the advanced systems such as
IGCC, where more concentrated streams under pressure improve capture
effectiveness, still results in increases in the cost of electricity by
30-40% compared to a modern pulverized coal plant with state of the art
emission controls. Reducing the cost and energy penalty associated with
the capture of CO2 is one focus of the research needed. This
is emphasized in the recently released National Coal Council report
3 that identified the opportunity for the U.S. to ``explore
a wide range of potential capture options, applicable to both
gasification and combustion systems, in the hope that breakthrough
technology can be identified to reduce the onerous costs and energy
penalties associated with current approaches.''
---------------------------------------------------------------------------
\3\ Coal-Related Greenhouse Gas Management Issues, National Coal
Council, May 2003
---------------------------------------------------------------------------
In order to meet the challenge of managing CO2 the U.S.
needs to accelerate the research and funding of work on carbon
sequestration. Programs like the one million tonnes per year
CO2 sequestration testing envisioned in the FutureGen effort
will help prove the long-term safety and effectiveness of
CO2 sequestration. However FutureGen by itself is not
sufficient to prove sequestration in all applications. As stated in the
National Coal Council report ``Given the number of possible sinks, and
likely regional differences in the characteristics of these sinks,
there is a need for several of these large-scale, long-duration
demonstrations.'' The challenge of funding this work is made even more
difficult since the ongoing DOE R&D program in coal and CO2
sequestration supports these long-term goals. It would therefore be
counterproductive to cut ongoing coal and CO2 research
programs in order to fund FutureGen and other large-scale
demonstrations. Both ongoing R&D and the new programs of large-scale
testing are essential.
The most critical needs for R&D in CO2 sequestration
include:
Development of advanced concepts for capture
Pilot and full scale demonstrations of direct sequestration
Carbon disposal stability
Support for indirect sequestration options such as forest
management and modified soil utilization practices
Summary
In order for the U.S. to solve the energy/environment conflict
encountered as a result of the growing demand for energy, two key
challenges must be solved.
We must sustain a strong, diverse electricity generation portfolio
and keep coal prominently in this mix. This will assure a secure
domestic energy supply by developing and deploying cleaner, more
efficient methods of producing electricity from coal.
We must accelerate the research and development of efficient,
environmentally sound carbon capture and storage technologies.
Thank you for the opportunity to address the Committee and I
welcome your questions.
Mr. Barton. Thank you.
The Chair recognizes himself for the first 5 minutes of
questions. This I think will be for Mr. Courtright and Mr.
Rudins. Are either of you familiar with the coal gasification
plant that has been working down in Florida the last couple of
years?
Mr. Courtright. Yes.
Mr. Barton. Can you enlighten the subcommittee on what it
cost to build that plant, what its efficiency is today, and, if
you know, what it is generating electricity at in terms of
dollars per megawatt?
Mr. Rudins. The Tampa electric plant has been a highly
successful plant. It has completed its commercial demonstration
phase and recently entered commercial service. It has been
shown to have very reliable operation with efficiencies close
to 40 percent. The approximate cost, if you take the total DOE
and private dollars that went into the project and divide by
the net power output, is on the order of $1,200 a kilowatt or
so. Its emissions have been extremely low and its permit
requirements for commercial operation have actually been even
lower than for the demonstration phase, and they have been able
to meet those requirements. So it is very much a success story.
I am not sure what the cost of electricity numbers are that
correspond to that.
Mr. Courtright. My understanding, the cost of electricity
is fairly comparable to that selling on the grid. There is
probably only one point that could be enhanced there, and that
is the overall availability is in the 75 percent range. I
understand that is a rough number. Most plants are trying to
get up in the 80 percent range. They broke into the 80's in
certain quarters, to my understanding. But with improvements,
that should occur.
Mr. Barton. In terms of the costs per kilowatt, we say it
is in the $5 or $6 per kilowatt.
Mr. Courtright. Megawatt.
Mr. Barton. Kilowatt would be a lot. Just a few zeroes. So
is that plant--what is the proprietary of the blueprint? Can it
be replicated around the country or are there patents involved?
If we wanted to say there is something very close to this and
we want to order 20 of these next year, are we ready to do
that?
Mr. Rudins. A number of companies have actually been trying
to develop IGCC projects based on that and to go forward. There
are intellectual property rights and equipment vendors own some
of those rights. Texaco owns the right to the Texaco gasifier.
But in fact, the Tampa plant can be replicated under the right
economic conditions and market conditions.
Mr. Barton. It is not something--in the beginning of the
nuclear power industry, each plant was totally unique; and if
you built another one, you redesigned it from scratch. The
basic design can be replicated fairly routinely, is that true?
Mr. Rudins. They can be replicated, but it really depends
on the customer. Historically, the utility customer wanted
specific designs and imposed specific site-related requirements
that had to be met, which would have required a departure, from
a straight replication.
Mr. Barton. To rephrase the question, if we were to build a
plant like that in another part of the country, would it cost
$1,200 a megawatt to build or can we get this economy of scale
where we standardize design, where we get it down in the $400
to $500 per megawatt?
Mr. Rudins. With each replication it is expected the cost
will come down. And after perhaps two or three replications, it
might approach that of a conventional coal power plant.
Mr. Barton. What are the nonfinancial barriers in the
industry to bringing this new technology into play? Is there a
tradition amongst the utility management that we don't want to
use these kind of plants because we haven't worked the kinks
out of them, or is there a pretty good shot that with proper
incentives and things like that, you find ready acceptance to
this new technology?
Mr. Courtright. What you have is that, there being two
plants in the U.S., both of those are single-trained
gasification plants for availabilities in that 70 percent
range. Most power companies are looking at this technology as
their next option; either that or advanced pulverized coal and
clean up on the back end. The main nonfinancial barrier, I
think, is the lack of understanding of how it fits into their
fleet, the development of operators to operate that plant. They
don't have people who are trained in those facilities. They are
trained on current-day technology, the experience of their
maintenance staff and everything else. So we need these second
and third plant demonstrations and also more education and
training of the future owners of these plants to be able to
feel comfortable taking them on and to operate them in a
competitive marketplace.
Mr. Barton. My time has expired. The gentleman from
Virginia, Mr. Boucher, is recognized for 5 minutes.
Mr. Boucher. Thank you very much, Mr. Chairman.
Mr. Rudins, let me ask you a couple of questions with
respect to the FutureGen project. You testified at some length
in your opening statement. As I understand the proposal, the
Federal Government's share of the cost would be approximately
$800 million?
Mr. Rudins. That is correct.
Mr. Boucher. Where is that money going to come from? Is it
going to be new money, we all hope, or will this be a
reprogramming of money from other coal research and development
initiatives?
Mr. Rudins. As was proposed in the fiscal year 2004 budget
request to the Congress, we propose to use prior-year, clean
coal dollars that would be deobligated from terminated projects
to get started with the project. And we would intend to work
with Congress to make those dollars available.
Mr. Boucher. Have you asked for any new money for this?
Mr. Rudins. Not at this time.
Mr. Boucher. Do you intend to?
Mr. Rudins. The concept was to start the initial project
phases with deobligated prior-year dollars, then the new
dollars would be requested once these dollars would be
expended.
Mr. Boucher. You are not anticipating any reprogramming of
funds from either CCT or the CCPI programs beyond what you have
already asked for in terms of reallocating money from
terminated programs; is that correct?
Mr. Rudins. That is correct.
Mr. Boucher. And how much have you now asked for in terms
of reallocations from terminated programs? What is that dollar
amount?
Mr. Rudins. We have not formally submitted a request for a
specific amount, but we have currently deobligated $185 million
from one project and there could be a somewhat lesser amount
from a second project if it does not go forward.
Mr. Boucher. And how much would that project be?
Mr. Rudins. The total potential is in the $300 million
range.
Mr. Boucher. So you will be asking for about $500 million
in new money for FutureGen at some point.
Mr. Rudins. That is correct.
Mr. Boucher. Let me ask you about a different aspect of
this. All of the witnesses have mentioned to some extent the
potential of FutureGen to educate us on the potential for
carbon sequestration. Not only would electricity be generated,
but hydrogen, potentially, could be produced that could fuel
transportation; and, at the same time, the technology permits a
capture of the carbon stream, and then that would be
sequestered in some form. What experience do we have today,
what experience directly does the Department of Energy have
with deep underground injection or other forms of
sequestration, or are we entirely starting anew as we embark on
FutureGen in terms of gaining experience with sequestration
technology?
Mr. Rudins. There is already an experience base that is
growing as a result of our efforts under the sequestration R&D
program. We are involved in a number of international as well
as domestic projects, such as the Sleipner project in Norway
that is injecting CO2 underground. We are
participating with the Canadians in the Weyburn project, which
is also injecting CO2 underground. We have a number
of R&D activities underway to get a better handle on that.
Part of our general experience over many years is in
enhanced oil recovery with CO2 injection. While that
is not done for the purpose of CO2 storage, it gives
us knowledge of underground CO2 behavior and gives
us an opportunity to move forward.
In the future, the sequestration program is going to be
focusing on that element among others. In FutureGen, that will
be a very strong focus of the program.
Mr. Boucher. Does the desire to learn about sequestration
and deep injection technology drive this project to some
particular part of the United States? Are you looking for the
particular kind of geologic strata that would underlie the
location of the plant?
Mr. Rudins. Deep saline aquifers would be one candidate.
And they're available across a fairly large number of States.
But that certainly would be one consideration.
Another consideration if we are co-producing hydrogen and
electricity would be the proximity of the site to an
electricity grid to be able to sell the electricity generated.
Another consideration, though not mandatory for co-producing
hydrogen, is proximity to a refinery so that one could sell the
hydrogen or excess hydrogen that is not used in the refinery
process.
A third consideration would be if the process is in
reasonably close proximity to an enhanced oil recovery field,
some of the CO2 could be sold for enhanced oil
recovery. There are a number of features and the probability is
that no one single site will have all of those but would have a
number of features that would be very attractive for a
FutureGen site.
Mr. Barton. The gentleman's time has expired, but you have
got it if you want to ask one last question.
Mr. Boucher. Thank you, Mr. Chairman. Just briefly, at what
stage are you in the process of soliciting private industry
participation, which would have to contribute 20 percent of the
overall cost of this project? And could you describe the
process that you intend to go forward with in terms of
soliciting private partners?
Mr. Rudins. We recently issued an RFI request for
information laying out the concept the department would propose
to use to enter into a cooperative agreement with a cross-
section of the coal and power industry of the U.S., and laying
out an approach that would benefit the industry as a whole.
So we would seek to partner with a representative cross-
section of the industry, where they will be represented by at
least 30 percent of the coal producers and at least 20 percent
of the coal-based electricity generators. The contract would,
as proposed in the RFI. We would non-competitively negotiate a
cooperative agreement and then would subsequently competitively
procure most of the elements associated with FutureGen,
including site selection and in other components.
Mr. Boucher. Thank you, Mr. Rudins. Thank you, Mr.
Chairman.
Mr. Barton. Thank you, Mr. Boucher.
Mr. Whitfield is recognized for 5 minutes.
Mr. Whitfield. Thank you, Mr. Chairman.
Mr. Rudins, you had mentioned in responding to Mr. Boucher,
at least I understood you to say, $185 million would be
available that had been set aside for other projects, but you
are going to reprogram that money. Is that correct?
Mr. Rudins. No. There is one project that we entered into
discussions for termination by mutual agreement, from which
deobligated $185 million that is available for us to apply to
FutureGen.
Mr. Whitfield. And that is what you would like to do?
Mr. Rudins. Yes.
Mr. Whitfield. I know you have asked for a request for
information. What would be the next step?
Mr. Rudins. Well, we received something on the order of 40
or more comments that we are now reviewing. The RFI closed June
16. Was it June 16? Yes, I believe it was June 16.
On the basis of those responses, we will be issuing a
summary report of responses received. We will evaluate them and
make a judgment as to whether the responses we received are
consistent with the game plan that we laid out and whether we
can proceed with the strategy as described in the RFI to go
forward with the noncompetitive negotiation with the team to
meet certain specific requirements.
If our conclusion is that it is yes, then we immediately
intend to enter into negotiations for government and industries
partnerships to pursue the project.
Mr. Whitfield. And when would you expect to make that
decision?
Mr. Rudins. I don't have an exact date, but that could be
done fairly quickly. If our conclusion is that we do not have a
basis to go forward with a noncompetitive negotiation, then we
would have to do a competitive solicitation, which would delay
the process by about a year or more.
Mr. Whitfield. I see. Okay. There was some discussion
earlier about this plant in Tampa, Florida. What is the
difference in the plant in Tampa, Florida and the one in
Jacksonville, Florida?
Mr. Rudins. The Jacksonville, Florida one is an atmospheric
fluidized bed combustion system. The one in Tampa is the IGCC,
integrated gasification combined cycle, system.
Both are very successful. Both have achieved their
demonstration goals, but IGCC is the one we have been focusing
on as offering the greatest potential for integration with
carbon sequestration.
Mr. Whitfield. How old is the Jacksonville facility?
Mr. Rudins. It just very recently went into operation. I
don't recall the exact date.
Mr. Whitfield. And Tampa recently went into operation?
Mr. Rudins. Tampa has been operating for several years but
very recently went into commercial service operation.
Mr. Whitfield. Okay. Mr. Burke, one question I'd like to
ask you, I noticed recently--and maybe you refer to this in
your opening statement--that a report was issued by a group
called the Energy Futures Coalition. And some of the press
coverage of that report indicated that the coal industry and
your company specifically had agreed that there is a need for a
carbon cap. Is that true?
Mr. Burke. No, that is not true, Mr. Whitfield. The energy
future coalition group that I was involved in was a working
group to discuss possible policy options to reconcile
environmentalist concerns about climate with industry's
concerns about energy supply and energy production.
We were there as a working group. We were there as
individuals, not as representatives of any organization. And I
think while we had some useful and profitable discussion along
those lines, we didn't reach a consensus.
The working group wrote a report. And the working group
report accurately reflects that. It does help to frame the
discussion and the debate, but it clearly indicates that there
was no consensus that was achieved.
When the full report came out, the energy future coalition
full report was included with reports from other working
groups. Some of the front material in that report went well
beyond what we had agreed to within the working group. And
that's what the press picked up on and recorded. I think,
unfortunately, I was disappointed to see that because I thought
the discussions that we were having had potential to be
productive. And I hope that this misrepresentation of that in
the press hasn't derailed that prospect.
Mr. Whitfield. So despite what the press said, you all did
not agree?
Mr. Burke. No. We don't agree that there is a demonstrated
scientific basis for climate change based on carbon emissions.
And we certainly don't agree that a carbon cap is justified.
Mr. Barton. The gentleman's time is about to expire in 10
seconds. So you have got one quick question.
Mr. Whitfield. You have intimidated me, Mr. Chairman. So I
will just wait until later.
Mr. Barton. The gentlelady from Missouri is recognized for
5 minutes.
Ms. McCarthy. I am going to pass.
Mr. Barton. The gentleman from Pennsylvania is recognized
for I think 8 minutes.
Mr. Doyle. Thank you, Mr. Chairman.
Mr. Rudins, welcome.
Mr. Rudins. Thank you.
Mr. Doyle. I just want to reiterate or just ask again for
clarity purposes some of the questions that Mr. Boucher and
others had asked about FutureGen. Now, am I understanding that
you are looking at some $300 million in funds that are going to
be de-obligated? This one program you said was approximately
$185 million.
Mr. Rudins. That is correct.
Mr. Doyle. And then there is another program. Which program
would that be?
Mr. Rudins. These are individual projects.
Mr. Doyle. I see. That would get up to $115 million that
would give you your $300 million.
Mr. Rudins. There are two projects in clean coal that
haven't entered the design phase. And on one, we have agreed
with the participant to proceed to termination by mutual
agreement. And that is the $185 million one that I had
mentioned. The other one, the other project, we are not to that
point yet.
Mr. Doyle. I see. I guess what many of us up here are
worried about and want to make sure doesn't happen is we are
not robbing Peter to pay Paul here, that we are going to see
that monies aren't going to be taken from any existing programs
to fund FutureGen.
So it is your intent, then, to--and I just want to
reiterate this for clarity, too--seek $500 million in new money
to make up the other balance of the $800 million of Federal
commitment?
Mr. Rudins. The current plan is to seek those dollars in
the years that those dollars will be needed.
Mr. Doyle. How many fiscal years do you see that $500
million being spent? You are not going to ask for it all at
once. You are going to ask for it in stages. Give us an idea of
what you are----
Mr. Rudins. We anticipate the FutureGen project will
require 10 to 15 years to complete, 10 years if you are an
optimist, 15 years if you are a bit pessimistic on it. We
anticipate that--well, we haven't negotiated the agreement with
the private sector, which then will determine what the cash-
flow requirements are. But $300 million is probably sufficient
for the first 2 or 3 years or actually maybe even longer.
So we do not anticipate that a first appropriation of new
dollars would be needed until perhaps the third year or later.
And then it depends on the cash-flow requirements of the
project, but if you just do a linear division of 10 years into
$800 million, it is $80 million a year. And subtract from that
at the front end $300 million.
The profile won't be linear because there will be
construction phases and the like where there is probably a
traditional bell-shaped curve or a variation on that that would
be required.
Until we get down into more specific details and
negotiations of project specifics, it is difficult for me to
give you a----
Mr. Doyle. You see yourself asking for this money over a
10-year period is what you are----
Mr. Rudins. That is correct.
Mr. Doyle. Now, I understand that there is some optimism
that there are going to be some other international partners
involved with FutureGen. Are you currently discussing
partnership with anyone internationally?
Mr. Rudins. There is a meeting going on as we speak
associated with the carbon sequestration leadership forum,
which involves the participation of senior representation from
I believe approximately 14 countries, that is focused on
sharing information on carbon sequestration and exploring
possible future opportunities for joint projects. There will be
a few of those conversations.
That may be one opportunity for getting other countries to
participate. And if so, we would hope they would join the U.S.
Government in pursuing the project and contributing to the $800
million government price tag.
Mr. Doyle. Just one final question for you, Mr. Rudins. I
introduced a bill back in 1999, H.R. 1753, which was the Gas
Hydrate Research and Development Act of 2000, which was signed
into law by President Clinton. Many of us feel if we can just
get 1 percent of the gas located in hydrates that we could
produce, we could really more than double our natural gas
resource base.
Now, the fiscal year 2003 budget for gas hydrates was $9.5
million. And the President's 2004 budget request is $3.5
million, which is some 63 percent less than the program as
endorsed by industry and Congress and many of us feel could
delay the development of gas hydrates by 5 years. Why is the
administration under-funding the gas hydrates program?
Mr. Rudins. Mr. Doyle, I can't answer that question because
it is not in my office area. But I would be happy to take the
question back and give you an answer for the record.
Mr. Doyle. Yes. I would appreciate that and just want to be
sure that the administration is not looking at this program and
others to offset funding for FutureGen. We are talking about
de-obligated programs and new money for that $800 million.
[The following was received for the record:]
Methane hydrates hold great potential as source of natural
gas and our work to develop this resource is important and will
continue. However, in this tight budget year, we made the
decision to place more emphasis on the President's Hydrogen
Initiative.
Additionally, we are seeing increased interest from the
private sector in methane hydrates and are actively seeking
opportunities to partner with them in order to leverage the
limited public dollars available.
Mr. Rudins. Yes, sir.
Mr. Doyle. Thank you very much.
Dr. Burke, welcome. In one form of legislation and
potential regulation, there has been talk about controlling and
reducing mercury admitted from coal-fired plants. I know that
the reduction of NOX and SOX will result
in mercury reduction also, as you mentioned in your testimony.
And we have begun hearing about work being done to develop
technology to achieve this. You also noted that work is being
done to specifically control mercury. I have a couple of
questions related to this.
Why is it necessary to further limit mercury beyond the
reductions achieved as a co-benefit of NOX and
SOX reductions? And could you tell me and the
committee about the status of the development of that type of
technology, what type of research is ongoing, what is showing
the most promise, and what we should be doing to address
mercury capture and reduction?
Mr. Burke. Yes. And, to put it in context, the issue here
is run by a mercury MAACT ruling that EPA is currently engaged
in. The EPA lists the mercury MAACT graph rule in December of
this year. That is their schedule of final rule in December of
2004 with implementation in December of 2007. We don't know
what the mercury MAACT rule is going to be.
And so the regional research point of view--I think it is
important to look at all potential options for mercury control.
We do see mercury, as you said, as a co-benefit of
SOX and NOX control technologies.
Depending upon the specific type of coal that is burned and the
specific type of unit in which it is burned, the quantities
will vary. In some cases, that might be adequate to meet a
mercury MAACT rule. In other cases, it might not. And,
therefore, it might be necessary to have additional technology,
add-on technology.
The problem is that there is currently no commercial
mercury control technology designed specifically for coal-fired
boilers. We simply don't have it. And so we are faced with the
potential to have to meet a mercury MAACT built in 2007. So the
time is pretty short.
There are a number of options that are being explored right
now to do various types of processes, including things like
carbon injection, where powdered carbon is injected into the
flue gas to capture mercury. Again, the efficacy of that
depends a lot upon the type of coal that is being burned, flue
gas conditions and so forth. So we need to know more about
that.
The thing I emphasized is that time is very short. And
although the Department has, I think, a good program in this
area, it is going to be necessary to pursue that very
vigorously in the near term so that we know what the available
technology options are in time for utilities to be able to
employ them to meet the 2007 deadline.
Mr. Barton. The gentleman's time is expiring in 11 seconds.
Mr. Doyle. Mr. Chairman, thank you very much. I yield back.
Mr. Barton. Does the gentleman from Maine wish to ask
questions?
Mr. Allen. No.
Mr. Barton. Well, you have timed it perfectly.
Mr. Allen. Perfectly I guess from some point of view. If I
could, Mr. Chairman, I will try to be very quick. We are going
to just see for 1 second if I have got some things here that I
would like to ask.
Mr. Barton. Well, while the gentleman is thinking, in this
coal gasification, are there any limitations on the types of
coal that can be used? Are we going to get into an Eastern
coal/Western coal, high-sulfur/low-sulfur coal fight, or is the
technology universally applicable to any type of coal?
Mr. Rudins. Certainly different gasifiers' operating
characteristics can vary with types of coal, but my personal
view is that they are not going to be constrained by types of
coal. I don't know if my colleagues share in that view.
Mr. Barton. Dr. Burke, do you agree with that?
Mr. Burke. I think that you are going to see the same sorts
of tradeoffs you have for coal using conventional systems. The
higher BTU coals are going to have some advantages in terms of
their energy content. Lower-sulfur coals are going to have some
advantages in terms of ease of environmental compliance. There
are those kinds of tradeoffs that are going to occur, but I
think it is going to be pretty much the same sorts of tradeoffs
that we are currently seeing.
Mr. Barton. Any type of coal could be gasified?
Mr. Burke. Right, given gasifiers have different sorts of
configurations, different processes. And those processes will
determine which coal operates the best, but there are gasifiers
out there that are able to handle all types of coal.
Mr. Barton. Does the gentleman from Maine wish to be
recognized?
Mr. Allen. Thank you. I do, Mr. Chairman.
Mr. Barton. The gentleman is recognized for 5 minutes.
Mr. Allen. I will be brief. I apologize for not being able
to be here earlier. And what I ask may already have been
covered. If so, just tell me that, and I'll move on.
I wanted to ask about the administration's national
hydrogen energy road map. It states that 90 percent of all
hydrogen will be refined from oil, natural gas, and other
fossil fuels in a process using energy generated by burning
oil, coal, and natural gas. The remaining 10 percent would be
from water using nuclear energy.
Let me back up one moment. The statement is that that is
the goal because we don't have the technologies to develop
hydrogen from the sun or wind, that those technologies need
further development for hydrogen production in order to be
cost-effective. If we are spending a billion dollars to build a
single FutureGen coal plant, isn't it clear that the technology
needed to cleanly produce hydrogen from coal also needs further
development?
I am just curious if maybe Mr. Rudins or others could
explain why the administration isn't putting money into a
research project to develop hydrogen from wind, for example. So
the two-part question is how much work you need to do on coal
to develop hydrogen from coal; and, second, why not a similar
investment in wind?
Mr. Rudins. Let me answer your question on a general level.
My understanding of the national hydrogen initiative is, in
fact, to look at diversified sources of hydrogen, including
renewables, including fusion, including nuclear, including
fossil sources and that, in fact, explore all pathways to a
hydrogen future. That is my understanding of the overall
strategy.
I can't talk to the relative funding levels. I just don't
have sufficient knowledge to be able to do that.
Mr. Allen. Any other comments?
Mr. Burke. Yes. The hydrogen production is chemically the
separation of water into hydrogen and oxygen. Water really
likes being water. It doesn't want to be separated. And so it
requires a substantial investment of energy to make that
happen.
It can be done by any of a variety of sources of energy. It
could be electricity that is produced by photovoltaics or it
could be heat that is generated through the gasification
process of coal. The question is really what the cost is. And
the cost of electricity from photovoltaics is relatively high
compared to the cost of producing that energy or providing the
energy through the gasification of coal. So that makes coal
relatively more attractive.
It doesn't preclude the possibility of those other sources,
but I think the issue is bringing down the cost of the energy
of providing those other sources and then looking to see if it
is competitive, basically providing the heat to get that
chemical reaction.
Mr. Allen. Okay. I hear you.
Mr. Courtright. Just to add a point on the wind and on the
solar aspect is the intimacy of that. You have those sources
only available at certain times, which limits the amount of use
you can get out of the capital investment for those for
producing electrolysis of water, for producing hydrogen. So it
does affect the economics of that.
Mr. Barton. The Chair made a decision on the administration
witness to bring the technical expert in DOE on coal programs,
as opposed to a political appointee, who could give a little
more general overview on the various ways to do some of these
things. Since this was a coal hearing, I chose the gentleman
who knows the coal programs, you know, absolutely coal. So if
you have a specific question on the administration, if you will
put it in writing, we can get you a broader answer from the
political appointees at DOE.
Mr. Allen. Fair enough.
Mr. Rudins. If I could give you a specific answer on coal
and its attractiveness, the issue with coal historically has
been it has been an abundant domestic fuel. It has been among
the lowest-cost fuels available to us. The environmental issues
have been always the obstacle for coal use.
The attraction of FutureGen is that if we are successful in
developing these technologies, it can eliminate all
environmental concerns associated with coal use, including
CO2 emissions. And if we are successful in doing
that, analysis connected by mitre analysis suggests that
hydrogen co-produced from coal with electricity, assuming
success in achieving program goals for sequestration, could be
the lowest-cost source of hydrogen.
Mr. Allen. That was going to be my other question. I don't
know if people have dealt with the issue of carbon
sequestration, but I wondered if you could give me some sense
of how much there----
Mr. Barton. Your time has expired, but I took some of it
up. Your last question.
Mr. Allen. Quick overview of what you think the role of the
coal industry should be in developing new approaches to carbon
sequestration.
Mr. Burke. Let me expound on that because I am from the
coal industry. I work for CONSOL Energy. We are a bituminous
coal producer. And I am here on behalf of them and the National
Mining Association.
I think the coal industry has a strong interest in
understanding the technical, financial, and environmental costs
and implications of this technology. And clearly to reconcile
our concern about environmental issues associated with carbon
emissions with the high degree of certainty that the world's
community will use its abundant coal resources requires some
way to deal with carbon dioxide through technology. And that
technology is carbon capture and sequestration. So I think from
a strategic point of view from the coal industry's perspective,
it is extremely desirable for us to see this technology
developed.
My company is involved with the department in doing one
project right now. We are looking at carbon sequestration in
coal seams. And we are a member of a group that has responded
to the FutureGen solicitation or FutureGen request for
information. So we would put a high degree of importance on
understanding what this is, where we can go with it, what it is
going to cost to do it, and what it is going to look like when
we get there.
Mr. Barton. The gentleman from Georgia. Do you want 5
minutes or 8 minutes? You are entitled to 8 if you wish.
Mr. Norwood. Eight.
Mr. Barton. All right.
Mr. Norwood. I can always give it back.
Mr. Barton. The gentleman is recognized for 8 minutes.
Mr. Norwood. Thank you very much, Mr. Chairman. I am sorry
I was out of the room. So I hope I am not going to ask a
question that has already been asked.
My first question is to any one of you, perhaps all of you.
I know all the members of the subcommittee know the answer to
the question. So I will ask this for the staff. If you will
explain to me and to them--do this simply if you can--how
exactly the IGCC technology works versus the pulverized coal
technology and how they will differ. In layman's terms, how do
those two technologies differ? And what are they? How do they
work?
Mr. Courtright. I think I will take a stab at it in
layman's terms. In the pulverized coal, you basically take
coal, crush it to a fine, almost powder substance, blow it into
a boiler and ignite that. So you essentially have a large fire
in a boiler where you are producing mostly super critical
steam, high-temperature steam, to run a steam turbine. And that
is how predominant pulverized coal plants operate. They burn
coal. You are dealing with large volumes of air, large volumes
of CO2 in a very diluted sense because you have
large volumes of air. And then you clean up those emissions at
the back end of that technology.
In layman's terms, gasification is basically taking the
solid of coal and chemically basically heating it and turning
it into a gas state. You are dealing with much more
concentrated streams of energy. About one-twentieth the volume
I believe is the right number. So capturing emissions is a lot
easier. Capturing CO2 is a lot easier because of its
higher concentrations, higher pressures. And that allows the
added ability of cleanup from an IGCC.
What has been the technology challenge has been the
gasification of coal in a very reliable sense as compared to
the burning of coal. And that has caught up and has basically
become a reliable process. Is that in a layman's enough for
you?
Mr. Norwood. Yes. That is good.
Mr. Courtright. Thank you.
Mr. Norwood. Additionally, you say that it is easier to
capture the emissions in IGCC than the gasification.
Mr. Courtright. Yes.
Mr. Norwood. Does that mean it is not just easier but you
capture more emissions?
Mr. Courtright. You are dealing with more concentrated
streams. So you probably can capture higher percentages, I
believe, and be able to do that with the amount of equipment
that you have to put on. In the pulverized coal plants, you are
dealing with very large volumes of air moving through equipment
and having to capture all of that through those large volumes.
Mr. Norwood. So it is cleaner emissions in the IGCC?
Mr. Courtright. Yes.
Mr. Norwood. Easier to do as well?
Mr. Courtright. Yes. That can be designed for better
emission cleanup.
Mr. Norwood. Does that mean less expensive, more expensive
because this new technology I guess you could say is more
expensive?
Mr. Courtright. Well, when we get to what we think is going
to be the state of costs for IGCC, we think it is comparable.
Your cost for electricity out will be about the same, not
counting the cap for CO2.
Mr. Norwood. Mr. Rudins, on the FutureGen, do you think the
number of a billion dollars in funding is adequate for that?
Mr. Rudins. By our estimates, yes, it is, sir.
Mr. Norwood. If this is a good idea, what is your
expectation in the private sector and their willingness to
invest private capital into this?
Mr. Rudins. At the state of where the technologies are, we
are looking at FutureGen as really a large-scale research
project, not a demonstration project. In commercial
demonstration projects, we typically seek 50 percent cost
sharing. With this being a more risky and longer-term
undertaking, as is typical in a research project, we are
seeking 20 percent cost sharing from the industry.
Mr. Norwood. Well, when might FutureGen, that type of
plant, be economically competitive out there? When do you guess
that might be?
Mr. Rudins. If we achieve the goals that we have laid out
for the FutureGen project and we complete it within a 10-year
horizon, we hope to show the ability to cost-effectively co-
produce hydrogen electricity and sequester the CO2
within the timeframe of that project. But more than likely, as
is typical for new technology, you probably would have to have
a commercial demonstration of that in a full commercial-scale
plant after that.
So if you are looking at time lines, about 10 years to
complete FutureGen and probably another 7 years or so to do a
commercial demonstration of that.
Mr. Norwood. So you are telling me that if we will invest
in this demonstration project or whatever you want to call it,
20 years from now, Southern Company is going to say, ``We don't
need any help from the government. We will use our own capital.
And we will be building FutureGen plants''?
Mr. Rudins. In that approximate timeframe, give or take
some years, yes.
Mr. Norwood. What might Congress do in any of your opinions
to stimulate, I guess is the right word, the more rapid
development of coal-based technology? What else do we need to
do?
Mr. Burke. I think we have laid out in this road-mapping
process--it is important to recognize that different groups of
people have had different technology road maps. And over the
course of the last couple of years, we have really caused them
to converge: the Department of Energy, industry, EPRI.
And I think the important thing is to continue to refine
and develop that road map to understand where we are going,
what the performance cost criteria area that we set, what we
need to do in technological detail to get to those points, and
cost that out and then provide the funding to be able to do it.
So it is really a question I think to be able to move along
that path at the rate at which we need to go, there is an
indicated funding level.
As I said in my oral remarks and my written testimony,
currently the funding that is in this year's appropriation, for
example, is only a little over half of what we think is
necessary to follow that road map schedule.
Mr. Norwood. That is sort of what I got out of your
testimony, too, Dr. Burke, is send money, a don't bother us,
send money sort of thing. And I am sort of asking, are there
other things that Congress needs to consider here? I know the
Department of Energy is on top of it, but are there are other
things that--and you don't have to do this right now; I am just
sort of thinking out of the box--other things that we might do
as a Congress besides send money to stimulate this?
Mr. Chairman, I yield back.
Mr. Burr. The gentleman's time has expired.
The Chair would recognize the gentleman from California.
Mr. Waxman. Mr. Chairman, I am not sure I can complete my
questioning in time to get to this vote. Could we come back? Do
you know how much time we have left before the vote?
Mr. Burr. I believe the gentleman has about 7 minutes.
Mr. Waxman. Well, if I have that much time, let me go
ahead.
Mr. Burr. I will double-check with Jim when you start. We
will get you an answer.
Mr. Waxman. All right. If you will protect my rights here?
Dr. Burke, you testified there may be mercury reductions as
a co-benefit of controls of other pollutants and ``In the long
run, it may be necessary to develop and deploy technology to
further limit mercury.'' Are you testifying today that Congress
should weaken the Clean Air Act so that the mercury MAACT
standard will not go into effect in 2004?
Mr. Burke. No.
Mr. Waxman. How would you reconcile that with the time that
we are looking at for this standard, which is supposed to be
prepared by the end of this year, finalized by next year, and
solved by 2007?
Mr. Burke. I think the time between now and December of
2007, we are not starting afresh today. The work on mercury
reduction and mercury technology has been underway for some
time. The Department has several large projects going on right
now looking at different technologies for mercury control.
And we don't know what MAACT is going to be at this point.
So without knowing specifically what the rules are going to be,
it is hard to say how we are going to achieve it.
Again, two things, the issues, the technology if it is
installed for other purposes will reduce mercury. There is a
program going on between the Department of Energy, private
industry--my company I think has four projects in this area--to
try to develop technology and understand how to reduce mercury
emissions costs effectively.
I think the most important thing is time is of the essence.
And we need to make sure that that work gets done right now.
Mr. Waxman. I read in your testimony that there are no
commercially available methods to control emissions of mercury
from coal-fired power plants. I think this is a highly
misleading statement, if not false.
The American Council, Coal Council, is an alliance of
companies that have the objective of advancing and utilizing
coal as an energy fuel source. Are you familiar with the
American Coal Council? Would you consider it a credible source
of technical information for the industry?
Mr. Burke. I am familiar with American Coal Council.
Mr. Waxman. I would like to submit for the record an
article from the American Coal Council's most recent magazine.
The article is entitled ``Tools for Planning and Implementing
Mercury Control Technology.'' This article finds that recent
full-scale demonstrations have proven the effectiveness of
powdered activated carbons in reducing mercury emissions. Let
me read to you from this article.
Mr. Burr. Does the gentleman want it in the record?
Mr. Waxman. I do.
Mr. Burr. Without objection, so ordered.
[The American Coal Council magazine article follows:]
Tools for Planning & Implementing Mercury Control Technology
Michael Durham Ph.D., President, ADA Environmental Solutions, LLC
During the past few years a great deal has been learned about the
capabilities and limitations of various technologies for controlling
mercury for coal-fueled boilers. New operating and performance data
from full-scale installations can provide guidance on determining the
most cost-effective approach for a particular plant.
New data and continued analysis of available information corrects
many of the early misconceptions about mercury control. For example, it
was once believed that wet scrubbers could be used to provide
dependable high-levels (90%) of mercury control. We have since learned
that mercury removal in scrubbers varies significantly from plant to
plant and is dependent upon coal characteristics and boiler operating
conditions. It was also speculated that the addition of Selective
Catalytic Reduction technology (SCR) could guarantee effective removal
of mercury in a downstream scrubber. Recent tests have demonstrated
that this is untrue.
Recent full-scale demonstrations have proven the effectiveness of
powdered activated carbon (PAC) injection for reducing mercury
emissions for different coals and control configurations. Results
indicate that this near-term technology will be well suited to be
retrofit on existing coal-fueled boilers. It requires minimal new
capital equipment, can be retrofit without long outages, and is
effective on both bituminous and subbituminous coals. Because of the
promise shown by PAC injection to control mercury emissions from all
types of coal, it appears unlikely that compliance with pending mercury
reduction regulations will result in significant fuel switching.
mercury emissions from coal-fueled boilers
Coal contains trace levels of mercury that are released when coal
is burned. The mercury forms various chemical species in the boiler
depending on the coal characteristics and the boiler operating
conditions. Elemental mercury, also referred to as mercury zero (HgO),
is not water-soluble and therefore cannot be captured in wet scrubbers.
Oxidized mercury, also known as reactive mercury, ionic mercury,
mercury chloride, and mercury plus two (Hg++) is water-soluble and can
be captured in wet scrubbers. While oxidized mercury can be captured,
it may not necessarily be fully retained due to subsequent reactions
leading to some re-emission of elemental mercury.
During 1999, EPA conducted an Information Collection Request (ICR)
program in which approximately 40,000 samples of coal were analyzed to
determine the concentration of mercury and chlorine. The ICR data
demonstrated that there is not a great deal of difference in the coal
types nor is there a large supply of ``low-mercury'' coal. Therefore,
in contrast to the situation with coal-sulfur content, coal switching
will not be a widespread option to meet a mercury regulation.
This data also showed that there was a significant difference
between the chlorine content of Eastern and Western coals. The Western
coals, both bituminous and subbituminous, have very low chlorine levels
with most having less than 100 ppm. The Eastern bituminous coals have
very high chlorine levels, many exceeding 1000 ppm. Because of this the
speciation of mercury in Western fuels favors the elemental form
whereas the Eastern coals have a higher concentration of the oxidized
forms of mercury.
EMERGING REGULATIONS
New air pollution control regulations that include limitations for
mercury emissions from coal-fueled boilers are coming from a variety of
fronts. EPA announced in December of 2000 that they would proceed to
develop a Maximum Achievable Control Technology (MACT) Standard for the
industry. A draft regulation will be submitted by December 2003 with
full implementation in 2007. The MACT process does not allow emissions
trading, and could establish different limits according to the type of
coal and type of air pollution control equipment at each plant.
Several bills are being debated in the Senate and the House that
would require reducing mercury emissions. The bills differ in the level
of mercury reduction required (50 to 90%), the timing of the reduction
(2008-2018), and whether emissions trading will be permitted. In
addition, several states have either passed new regulations for mercury
control or are in the process of drafting regulations. The most
aggressive have been the New England states where mercury control will
be required in Massachusetts and New Hampshire by 2006.
MERCURY CONTROL IN EXISTING EQUIPMENT
The ICR program also provided insight on the capabilities of
existing Activated Powdered Carbon (APC) devices to control mercury and
the impact of coal characteristics. For every type of APC device,
mercury capture was higher for bituminous coals than for subbituminous
coals.
The ICR program also provided insight on the capabilities of
existing APC devices to control mercury and the impact of coal
characteristics. For every type of APC device, mercury capture was
higher for bituminous coals than for subbituminous coals. This is due
to the higher levels of oxidized mercury, higher concentrations of HCI,
and higher levels of carbon in the ash. It also showed that fabric
filters enhance the capture of mercury compared to electrostatic
precipitators (ESPs),
The ICR tests confirmed that wet and dry scrubbers, which are
located on 25% of the power plants, could be effective for removing
mercury from some coals. However, scrubbers are only effective at
removing one form of mercury, mercury chloride, and cannot remove
elemental mercury. Because of this limitation, mercury control with
scrubbers varies from less than 10% up to 90% removal. They work best
on bituminous coals with high chlorine levels and they are quite
ineffective on western subbituminous coals. This will severely restrict
fuel flexibility at plants that depend upon scrubbers for mercury
control. Following the ICR tests, additional test programs have been
sponsored by EPRI and U.S. Department of Energy (DOE) to determine if
SCR catalysts installed for NOx control are effective at oxidizing
mercury to enhance removal in scrubbers. Their results show that while
fresh catalysts can oxidize some elemental mercury to mercury chloride,
performance depended upon coal characteristics. The test also
demonstrated that the amount of oxidation decreases as temperature and
gas flow increase, was inhibited by the addition of ammonia, and
decreased rapidly over time at normal operating conditions. Several
full-scale SCR units showed no appreciable mercury oxidation.
One of the most difficult applications for controlling mercury will
occur at plants that burn Western fuels and use dry scrubbers for S02
control. Analysis of units using fabric filters has shown that for
subbituminous coal, the mercury removal on plants with spray dryers
(~5-39%) was lower than for plants without spray dryers (~55-82%). This
inhibition of mercury removal appears to be caused by the elimination
of HCI from the gas stream. Tests conducted by EPRI confirmed that
these trends also occur when activated carbon is added to enhance
mercury capture. For example, at a PAC feedrate sufficient for 90%
mercury capture, mercury removal was reduced to 50% by the presence of
a spray dryer.
Tests have shown that iodated carbon is capable of 90% mercury
removal in this application. Although the iodated sorbent is
prohibitively expensive, it does indicate that the problem might be
solved with modified sorbents. EPRI has performed full-scale tests
adding chloride compounds to the gas stream with some limited success.
issues related to corrosion and deposition must be addressed for this
to be a viable approach.
ACTIVATED CARBON INJECTION
Injecting a sorbent such as powdered activated carbon (PAC) into
the flue gas represents one of the simplest and most mature approaches
to controlling mercury emissions from coal-fueled boilers. This
technology has been used for decades to control mercury emissions from
boilers burning waste. Figure I is a photograph of the sorbent silo and
feed train designed to inject PAC to treat a 150 MW boiler. The gas
phase mercury in the flue gas contacts the sorbent and attaches to its
surface. The sorbent with the mercury attached is then collected by the
existing particle control device, either an electrostatic precipitator
(ESP) or fabric filter (FF).
The most commonly used sorbent for mercury control has been
activated carbon. Activated carbon is carbon that has been ``treated''
to produce certain properties such as surface area, pore volume and
pore size. Activated carbon can be manufactured from a variety of
sources, (e.g. lignite, peat, coal, wood, etc.).
FULL-SCALE DEMONSTRATIONS OF ACTIVATED CARBON
Under a cooperative agreement from the DOE National Energy
Technology Laboratory, ADA-ES worked in partnership with PG&E, We
Energies, Alabama Power, Ontario Power, TVA, First Energy, EPRI, Hamon,
Arch Coal and Kennecott Energy on a field test program of sorbent
injection technology for mercury control. The test program took place
at four different sites during 2001 and 2002.
Figure 2 presents full-scale data from three test sites, one with a
FF on a bituminous coal, and two with ESPs, one bituminous and the
other PRB. This plot also includes reduced-scale FF tests conducted by
EPRI on a PRB coal. In all cases, mercury removal increases with
increased rates of carbon injection. The best results occur on units
with fabric filters as removal levels as high as 90% are achieved at
much lower sorbent rates than that required for an ESP. It also shows
that the performance in a FF appears to be independent of the type of
coal.
With the ESPs, there does appear to be somewhat different results
for bituminous and PRB coals (i.e. up to 90% removal in the bituminous
case). However, because of the costs associated with the higher sorbent
rates for ESPs, the practical limit for PAC injection with ESPs for all
coals is 50 to 70% removal.
These tests also demonstrated that for all coals and both APC
devices, collection efficiency was nearly identical for both elemental
and oxidized mercury. These results validate the capability of PAC to
capture all forms of mercury from both bituminous and subbituminous
coals.
The data presented in Figure 2 can be used to estimate the impact
of various mercury control regulations. The only practical way of
assuring 90% mercury removal would be to inject PAC upstream of a FF.
However, currently only 10% of existing plants have FFs. Thus 90%
regulations would require most plants to install these devices at a
capital cost of $40/kW. However, a regulation requiring 50-70% removal
could be met by many plants with PAC injected upstream of existing APC
equipment.
MERCURY IN COAL COMBUSTION BYPRODUCTS
Since the purpose of controlling emissions from coal-fueled boilers
is to reduce potential buildup of mercury compounds in lakes and
streams, the stability of mercury captured is a critical component of
the, overall control scheme. In addition, there is a concern over the
impact of PAC on ash being sold for use in concrete.
Currently there are a number of programs being conducted by DOE,
EPRI and the Environmental Protection Agency (EPA) to evaluate the
stability of mercury captured in flyash and scrubber sludge. These
programs are establishing a number of new protocols to evaluate the
susceptibility of these materials to leaching and volatilization of
mercury compounds under ``worst-case'' environmental conditions. To
date results have been very promising, as the captured mercury appears
to be unlikely to reenter the biosystem.
Although the ash appears to be stable, tests have confirmed that
the presence of even trace amounts of PAC rendered the ash unacceptable
for use in concrete. This would not be an issue for the two/thirds of
the plants that landfill their ash, but is an important economic factor
for those plants that do sell their ash.
Several approaches are being considered to insure that the ash
remains marketable such as separation, combustion and chemical
deactivation of the PAC in the ash. One straightforward approach that
is currently commercially available is the arrangement in which PAC is
injected upstream of a secondary baghouse located downstream an ESP.
With this configuration, the ash is collected upstream of the carbon
injection and remains acceptable for sale. ADA-ES has begun work on two
long-term full-scale demonstration programs of this configuration at
the Alabama Power Gaston Station burning bituminous coal, and at the We
Energies Presque Isle Station burning PRB coal
CONCLUSIONS
The power industry in the US is faced with meeting new regulations
to reduce the emissions of mercury compounds for coal-fueled plants.
These regulations are directed at the existing fleet of nearly 1100
existing boilers. A reliable retrofit technology is needed for these
plants that minimizes the amount of new capital equipment while
providing continued flexibility in fuel selection. However, mercury
removal in wet scrubbers has been proven to vary significantly from
plant to plant and is dependent upon coal characteristics and boiler
operating conditions. It is also becoming more obvious that the
addition of an SCR does not guarantee effective removal of mercury in a
downstream scrubber. On the other hand, recent full-scale demonstrates
have proven the effectiveness of activated carbon injection for
reducing mercury emissions. This technology is simple and near-term and
provides the capability of removal of all species of mercury from both
Eastern and Western coals.
Additional information on mercury control can be found on the NETL
(www.netl.doe.gov) and ADA-ES (www.adaes.com) websites.
ADA Environmental Solutions, LLC (ADA-ES) is an environmental
technology and specialty chemical company headquartered in Littleton,
Colorado. The company brings 25 years of experience to improve
profitability for electric power and industrial companies through
proprietary products and systems that mitigate environmental impact
while reducing operating costs. ADA-ES is a subsidiary of Earth
Sciences, whose common stock trades on the OTCBB under the symbol ESCI.
Mr. Waxman. ``The results indicate that this near-term
technology will be well-suited to be retrofit on existing coal-
fueled boilers. It requires minimal new capital equipment, can
be retrofit without long outages, and is effective on both
Eastern and Western coals. It appears that in combination with
a fabric filter, this technology will reliably remove 90
percent of mercury from either Eastern or Western coal.'' Dr.
Burke, do you have information that this evidence from the
American Coal Council is incorrect?
Mr. Burke. I think that refers to pilot plant tests of
mercury carbon injection. They are relatively short-duration
tests of some specific coals and some specific boilers.
I don't dispute that. I don't know the source. I don't know
the information except that that is true. There have been a
number of tests. And they have shown some promising results.
What I was referring to in my technology was the lack of
application of that commercial-scale across the wide spectrum
of the existing coal-fired utility plants.
Mr. Waxman. Well, I am going to submit this for the record.
Perhaps you can also look at it and respond to us further for
the hearing record. If there are additional issues to address,
won't the industry will have an opportunity to comment once EPA
issues a proposal at the end of this year?
Mr. Burke. Yes, that is my understanding.
Mr. Waxman. Okay. Thank you. Thank you, Mr. Chairman. We
will make this part of the record. I would like to submit it
for comment.
Mr. Barton. Is it acceptable to you, Mr. Waxman, if we let
this panel go?
Mr. Waxman. I have no problem.
Mr. Barton. We are going to thank you gentlemen for your
participation in this issue and ask for our second panel to
come forward. Thank you.
If the subcommittee could come forward? If our panelists
could get located? If we could be reseated? We would like to
begin. Is Mr. Olliver here in the room? We have got a name
place, Dick Olliver. All right. We are going to start without
Mr. Olliver.
We are going to start with Mr. Brian Ferguson, who is the
Chairman and Chief Executive Officer of the Eastman Chemical
Company. He is testifying at the request of Congressman
Boucher. I am sure if Mr. Boucher were here, he would say some
nice things about you. We will give him that opportunity when
he returns.
Your testimony is in the record. We are going to recognize
you for 5 minutes to elaborate on it. Hopefully by that time,
we will have some other Congressmen back. Welcome to the
subcommittee, Mr. Ferguson.
STATEMENTS OF J. BRIAN FERGUSON, CHAIRMAN AND CHIEF EXECUTIVE
OFFICER, EASTMAN CHEMICAL COMPANY; CHARLES R. BLACK, VICE
PRESIDENT, ENERGY SUPPLY, ENGINEERING AND CONSTRUCTION, TAMPA
ELECTRIC COMPANY; RANDALL RUSH, POWER SYSTEMS DEVELOPMENT
FACILITY DIRECTOR, SOUTHERN COMPANY; RICHARD A. OLLIVER, GROUP
VICE PRESIDENT, GLOBAL ENERGY INC.; LAWRENCE E. McDONALD,
DIRECTOR, DESIGN ENGINEERING AND TECHNOLOGY, THE BABCOCK &
WILCOX COMPANY; DAVID G. HAWKINS, DIRECTOR, CLIMATE CENTER,
NATURAL RESOURCES DEFENSE COUNCIL; ROE-HAN YOON, DIRECTOR,
CENTER FOR ADVANCED SEPARATION TECHNOLOGIES, VIRGINIA TECH; AND
FRANK ALIX, CHIEF EXECUTIVE OFFICER, POWERSPAN CORP.
Mr. Ferguson. Thank you, Mr. Chairman.
I very much appreciate the opportunity to appear before you
to share the enthusiasm that Eastman has for the production of
electricity through coal gasification.
Eastman is a pioneer in the coal gasification business. In
the early 1980's we had two large ChevronTexaco coal
gasification units at our Kingsport, Tennessee chemical
manufacturing complex. This system was completed in 1983, and
we have made continuous process improvements since then.
Now, as we celebrate the 20th year milestone, Eastman is
widely recognized as the leading coal gasification operator in
the United States. To leverage this leadership position,
Eastman recently formed a subsidiary to help other gasification
project owners achieve faster startup, maximize their plant
values, and improve long-term performance.
In a related development, we have signed a cooperative
agreement with ChevronTexaco, which allows us to provide
operation, maintenance, management, and technical services to
other ChevronTexaco gasification licensees.
As Eastman has marketed its gasification expertise, we have
repeatedly encountered three questions about coal gasification-
based electrical power plants. I've heard those questions again
here today. Those questions are how expensive are they to build
and operate, are they reliable, and what are the environmental
benefits? I would like to elaborate on each of those a little
bit in turn.
Question one, how expensive are coal gasification power
plants to build and operate? Mr. Chairman, based on our 20
years of operating experience, we believe that coal
gasification can be competitive right now. We strongly believe
this. And it is becoming more cost-competitive with each
passing day. Let me cite some specifics.
According to data compiled by Eastman, ChevronTexaco,
General Electric, and others, the capital costs of coal
gasification power plants are currently projected to run around
$1,200 to $1,400 per kilowatt of capacity. I think that was
testified to in the earlier panel. And they are trending
downward over time, as you asked about. This compares favorably
with the newest generation of pulverized coal power plants,
which have projected capital costs in that same range but are
trending upward as additional pollution control restrictions
are required.
Although operation and maintenance costs are somewhat
higher for coal gasification plants, these costs are offset by
lower fuel costs from the higher efficiency that was testified
to and by lower environmental treatment costs and subsequent
waste disposal costs. In addition, the coal gasification
process produces saleable byproducts, such as elemental sulfur
that we produce from the capped sulfur dioxide. As additional
commercial-sized coal gasification plants are built, the cost
competitiveness of this environmentally superior technology
should become more evident.
Question two, how reliable are gasification power plants?
Mr. Chairman, this is also a question that Eastman is uniquely
qualified to answer. Our system with its dual gasifiers has
achieved on-stream availability of 98 percent since 1984 and an
estimated single gasifier availability of 90 percent. That
compares to the 70 percent numbers you heard earlier being
demonstrated in the TECO facility. Perhaps most remarkably, our
forced outage rate is only about 1 percent.
With respect to performance, Eastman has continuously
improved the performance of our gasification system. For
instance, the time between gasifier switches,--this is a time
for moving between one gasifier to another--is now about once
every 2 months, which is a 6- or 7-fold improvement from where
we were 20 years ago. Another useful measure of performance is
maintenance costs. In the last 6 years alone, annual
maintenance costs for our gasification systems have declined by
over 40 percent.
Question three, what are the environmental benefits of coal
gasification? Mr. Chairman, let me answer that simply and
directly. The principal environmental benefits associated with
coal gasification, as compared to coal combustion processes,
are: in the short term, significantly lower emissions of
serious air pollutants, such as sulfur dioxide, NOX,
and I should say almost virtual removal of volatile mercury.
And in the long term, we have more cost-efficient and cost-
competitive carbon dioxide capture technologies available if
they are chosen.
There are many more environmental benefits of coal
gasification, but all that you need to take away from this
hearing is the simple fact that it is by far the cleanest of
the clean coal technologies.
Before concluding, let me express Eastman's support for
both FutureGen and the clean coal power initiative. The
electric industry is highly regulated and, hence, conservative
when it comes to embracing new technologies. So, even though
Eastman believes that coal gasification is ready for further
commercialization right now, some additional market incentives,
such as the CCPI and the proposed clean coal tax credits, are
useful and necessary inducements. We thank the members of this
subcommittee for your leadership on these specific issues and
on advancing coal gasification in general.
Mr. Chairman, let me summarize my testimony. We believe
that gasification is economically competitive with other clean
coal processes now. It is the environmentally superior coal-
based technology. And, as Eastman has proved through 20 years
of experience, coal gasifications can be operated at maximum
efficiency with a high-degree of reliability. And we would
invite any interested members in this room to come see that
with their own eyes at their convenience.
Thank you for this opportunity to appear before the
subcommittee this afternoon. I have offered extended remarks
for the record. And I would be happy to answer questions.
[The prepared statement of J. Brian Ferguson follows:]
Prepared Statement of J. Brian Ferguson, Chairman and Chief Executive
Officer, Eastman Chemical Company
Mr. Chairman and members of the subcommittee, I appreciate the
opportunity to appear before you to share the enthusiasm that Eastman
has for the production of electricity through coal gasification.
Eastman, as you know, is a pioneer in the coal gasification business.
Our coal-to-chemicals facility in Kingsport, Tennessee, has just
reached the 20-year milestone, so we have a lot of knowledge and
credibility with respect to coal gasification generally. But before I
turn to the specific topics you asked me to address, let me take a few
minutes to provide some background information about Eastman Chemical
Company.
Eastman: A Proud History and an Exciting Future
Eastman is a global chemical company founded in 1920 by George
Eastman to provide chemicals for Eastman Kodak Company's photographic
business. We became independent from Kodak in 1994, and have grown
substantially since the spin-off. Revenues in 2002 were $5.3 billion.
Eastman supplies billions of pounds of chemicals, fibers, and
plastics each year to customers around the world who, in turn,
manufacture thousands of different consumer products. We serve many
diverse markets, including pharmaceuticals, textiles, packaging,
cosmetics, electronics, paint and coatings, and photography.
Eastman's most visible asset today is arguably our large portfolio
of products, but certainly one of our most valuable future assets is an
expanding portfolio of ideas. After 82 years in the chemical industry,
we have amassed an impressive body of technological and intellectual
assets and multi-faceted capabilities. These assets have the potential
to be developed into new technology-oriented service businesses that
are based on higher-value business models. This strategy is an
important part of Eastman's growth platform and a top priority for
senior management.
In that regard, a key business objective for Eastman is to use our
two decades of coal gasification experience to help other companies
design, build, and operate similar facilities for the production of
electricity, chemicals, or other end-products, such as hydrogen.
Eastman's Coal Gasification Experience
Many of the chemicals that Eastman produces at our Kingsport
complex are created through chemical reactions involving, at the front-
end of the process, simple molecules such as hydrogen (H2) and carbon
monoxide (CO). To produce these molecular building-blocks in the large
volumes required in subsequent steps of the manufacturing process, our
facility has always required great quantities of hydrocarbon raw
materials.
For many decades we relied upon petroleum as our principal
hydrocarbon feedstock. However, severe price increases associated with
two events during the 1970s--the oil embargo and the Iranian crisis--
encouraged Eastman to turn to coal as an alternative.
In the early 1980s we obtained a license from Texaco (now
ChevronTexaco) and installed two large coal gasification units using
the Texaco technology. The installation was completed in 1983 and we
have made continuous improvements to this system over the last 20
years.
Many experts consider Eastman to be the world's leading
gasification operator for the following reasons:
1. Ours was the first commercial coal gasification project built in the
United States.
2. We have the world's best operating performance. For the last 19
years we have enjoyed an on-stream rate of 98 percent (it was
91 percent in the initial startup year). And our annual forced
outage rate is now less than one percent.
3. We have an enviable safety record. Our Kingsport site has an OSHA
recordable rate of 1.0 and no lost time accidents in the last
11 years.
4. We have exceptional environmental performance. Our system removes
more than 99.9 percent of the sulfur in the synthesis gas
(syngas created from coal). We have a patented sulfur-free
gasifier start-up process. And we remove nearly all of the
volatile mercury present in the syngas stream.
5. Our continuous process improvements have resulted in a 40+ percent
reduction in annual maintenance costs over the last six years.
Eastman has such faith in the future of gasification that we have
formed a subsidiary--Eastman Gasification Services Company--to help
other gasification project owners achieve faster start-up, maximize
plant value, and improve long-term performance. In a related
development, we have signed a cooperative agreement with ChevronTexaco,
which allows us to provide operation, maintenance, management, and
technical services to other ChevronTexaco gasification licensees.
Mr. Chairman, I am very proud of the fact that Eastman is widely-
recognized as the premier coal gasification operator in the United
States. And I am honored to appear before you today to share some
insights based upon our two decades of operating experience.
Three Key Questions about Coal Gasification
As Eastman's gasification services team has marketed its expertise
to potential clients here and abroad, we have repeatedly encountered
three fundamental questions about coal gasification-based electrical
power plants:
1. How expensive are they to build and operate?
2. Are they reliable?
3. What are the environmental benefits?
These are the three essential questions, which Eastman and other
coal gasification proponents must answer convincingly if we hope to see
rapid and widespread deployment of this exciting technology.
Question 1: How expensive are coal gasification power plants to build
and operate?
When discussing the merits of coal gasification, it is tempting to
start by describing the environmental benefits of the process, since
those benefits are substantial. However, if you start such a discussion
with electrical power plant developers, they inevitably stop you in
mid-sentence. ``That's great,'' they always say, ``but how do the life-
cycle costs compare with other technologies?''
The answer to that question is one Eastman can uniquely address.
Based on our 20+ years of operating experience, we believe that coal
gasification can be competitive right now and is becoming more cost-
effective with each passing day. Consider these facts:
Capital Expenses. According to data compiled by Eastman,
ChevronTexaco, GE, and others, the capital costs of coal gasification
power plants are currently projected to run between $1,200 and $1,400
per kilowatt of capacity and are trending downward. This compares
favorably with the newest generation of pulverized coal power plants,
which have projected capital costs in this same range.
What has happened to make gasification competitive? Pulverized coal
capital costs have risen in recent years as the result of ever-
tightening federal air pollution and other environmental regulations.
Coal gasification, on the other hand, has fewer potential environmental
side-effects, and the capital costs of such plants are decreasing as
the electric power industry gains more familiarity with the technology.
Operational Costs. Although operation and maintenance
costs are somewhat higher for coal gasification plants, these costs are
offset by lower fuel costs (from higher efficiency) and by lower
environmental treatment costs and subsequent waste product disposal
costs. In addition, the coal gasification process produces saleable by-
products, such as elemental sulfur.
Mr. Chairman, total variable costs--O&M, fuel, waste product
disposal, and by-product credits--are currently better for coal
gasification than any other fossil fuel-based electric power generation
technology, including natural gas. Moreover, the costs associated with
the removal of volatile mercury and with carbon dioxide capture and
sequestration (if and when such removals are required) are much less
for gasification than for competing technologies.
Fuel Costs. In general, coal gasification is competitive
with natural gas when natural gas prices are in the range of $3.50-
4.00/million Btu. Many energy experts now predict that natural gas
prices will remain above $5.00/million Btu through most of this decade.
Sustained natural gas prices at that level would continue to harm
America's chemical industry, and at Eastman we hope that this scenario
will not occur. Unfortunately, a prolonged period of natural gas prices
in the $5.00-6.00/million Btu range seems likely.
In summary, when comparing capital costs, operational costs, and
fuel costs, we believe the generation of electricity from coal
gasification can be competitive right now. As additional commercial-
sized coal gasification plants are built, the cost-competitiveness of
this environmentally superior technology should become more evident,
especially if the best practices Eastman has developed over the years
are incorporated into future designs and operations.
Question 2: How reliable are coal gasification power plants?
Mr. Chairman, this is also a question that Eastman is uniquely
qualified to answer. As I mentioned earlier, we have successfully
operated a coal gasification system for the last 20 years, which is
longer than any other company in the United States.
Of course, some might argue that there is big difference between
running a coal-to-chemicals manufacturing facility and a coal-to-
electricity power plant. They'd be right. Running a chemical facility
is a lot more complicated. But the basic coal gasification process is
the same regardless of whether the ultimate end-product is chemicals or
electricity.
Based upon our two decades of operating experience, I offer the
following observations about the reliability and performance of our
coal gasification facility:
Availability. Eastman's gasification system has achieved
on-stream availability of 98 percent since 1984. Even during the
initial startup year we were on-stream 91 percent of the time. Perhaps
most remarkably, our forced outage rate is only about one percent.
While this extraordinary performance is due in part to that fact that
we have two gasifiers, with one unit always serving as a ``hot
standby,'' even our single unit availability rate is estimated to be 90
percent.
How critical is gasifier availability to Eastman? Let me put it
this way: losing the ability to generate synthesis gas can shut down a
significant portion of our Kingsport facility, which relies heavily on
syngas production. The potential cost of such a shutdown is incredibly
high.
Performance. Eastman has continuously improved the
performance of our gasification system during the last two decades. In
1983, for example, we were switching between gasifiers about once a
week. In 2002, on the other hand, we averaged 62 days between switches.
Another useful measure of performance is maintenance costs. In the last
six years alone, annual maintenance costs for the gasification system
have decreased by over 40 percent.
Question 3: What are the environmental benefits of coal gasification?
Mr. Chairman, let me answer that question simply and directly. The
principal environmental benefits associated with coal gasification are:
(1) significantly lower air pollution emissions in the short-term; and
(2) more cost-efficient carbon dioxide (CO2) capture and
sequestration in the long-term.
In the future, America's electricity requirements may be met
primarily by renewable energy sources such as wind and solar or perhaps
even by nuclear fusion. It is prudent for America to explore those
options. However, it is obvious to anyone who has studied our nation's
energy situation in depth that coal can and must continue to play a
leading role over the next several decades (at a minimum).
Unfortunately, there are two major environmental issues which the
public associates with traditional coal combustion processes and even
with much newer (and cleaner) coal combustion technologies:
1. When coal is burned it produces certain air pollutants, most notably
sulfur dioxide (SO2), nitrogen oxides
(NOX), particulate matter (PM), and mercury (Hg). In
coal-fired power plants these pollutants must be removed from
the exhaust (stack) gases using expensive and often relatively
inefficient processes.
2. The combustion of coal also produces substantial quantities of
CO2. If and when CO2 capture and
sequestration is eventually required, it will be difficult and
prohibitively expensive for coal-fired power plants to meet
such requirements.
By contrast, coal gasification is a chemical process. As such, it
is possible to remove the sources of SO2 and Hg and the
CO2 from the synthesis gas before combustion, when it is
much easier and thus less expensive to remove. Also, because the syngas
is much cleaner than the raw coal itself, lower quantities of
NOX and PM are produced during the combustion process.
There are many more environmental benefits of gasification such as
minimal solid waste generation, nominal water consumption, and the
generally pleasing aesthetics of facilities and operations. These
benefits have been adequately documented by both private and public
sector experts. All that you need to take away from this hearing
concerning the environmental benefits of coal gasification is a simple
fact: it is by far the cleanest of the clean coal technologies.
FutureGen and the Clean Coal Power Initiative
Mr. Chairman, I am pleased to publicly express Eastman's support
for FutureGen and the Clean Coal Power Initiative (CCPI), two research,
development, and demonstration programs initiated by the Bush
administration. Since you have asked the witnesses at this hearing to
address both FutureGen and the CCPI, I would offer the following
observations:
FutureGen. Eastman supports this program because we
believe that the government must lead the way in demonstrating both the
feasibility of large-scale hydrogen production from coal and the
sequestration of carbon dioxide from coal-based power plants. If
properly conceived and executed, FutureGen could help achieve these two
purposes while accelerating the commercialization of coal gasification.
However, we are concerned that budget constraints in future years will
make the 80 percent federal funding commitment to FutureGen difficult
to sustain.
If forced to choose between funding for FutureGen and the Clean
Coal Power Initiative, we would choose the latter. The CCPI program--
with its biennial competitive solicitations--provides a long-term
source of support for a diverse array of technologically promising but
commercially risky coal gasification process improvements. While the
goals of FutureGen are laudable, the CCPI is more important, in our
opinion, for the future of coal gasification.
Also, if the FutureGen project does go forward, Eastman agrees with
our colleagues on the Gasification Technologies Council (GTC) that this
project ought to be designed and executed in close collaboration with
the gasification industry.
Mr. Chairman, I have attached to this statement a copy of the
comments submitted by the GTC to the Department of Energy on the
FutureGen proposal, and I ask that you make these comments a part of
today's hearing record. The position of the gasification industry on
the FutureGen project is set out in detail in this document.
Clean Coal Power Initiative. Eastman supports the CCPI
program and we thank the members of this committee for including a
nine-year, $200 million per year, authorization for the CCPI within
H.R.6, the omnibus energy bill passed by the House of Representatives
earlier this year.
As you know, the CCPI authorization in H.R.6 includes a requirement
that at least 60 percent of the CCPI funds ``shall be used only for
projects on coal-based gasification technologies, including
gasification combined cycle, gasification fuel cells, gasification
coproduction, and hybrid gasification/combustion.'' Eastman believes
that this 60 percent minimum should be increased to 80 percent as is
the case in the bill presently pending before the Senate. (This
position was recently supported by a report from the National Research
Council.)
Given the serious federal budget limitations that lie ahead and in
light of the fact that gasification is the cleanest of the clean coal
technologies, we urge you and your colleagues to accept the Senate
position on this matter when the joint House-Senate conference
committee meets to iron out the differences in the two versions of the
energy bill.
The electric power industry is highly regulated and hence
conservative when it comes to embracing new technologies. Thus, even
though Eastman believes that coal gasification is ready for further
commercialization right now, some additional market incentives such as
the CCPI and the proposed clean coal tax credits are useful and
necessary inducements. We thank the members of this subcommittee for
your leadership on these specific issues and on advancing coal
gasification in general.
Concluding Thoughts
Mr. Chairman, the gasification services team at Eastman Chemical
Company has spent a lot of time contemplating the barriers--both real
and perceived--to widespread acceptance of coal gasification by the
electric power industry. Many of the perceived barriers have been
addressed at this hearing, and I hope that I have conveyed to you what
we firmly believe at Eastman--
1. Gasification is economically competitive with other clean coal
processes.
2. It is the environmentally superior coal-based technology.
3. And, as Eastman has proven through 20 years of experience, coal
gasification plants can be operated at maximum efficiency with
a high-degree of reliability.
Mr. Barton. Thank you, Mr. Ferguson.
We would now like to hear from Mr. Charles Black, who is
Vice President for Energy Supply, Engineering and Construction,
Tampa Electric Company. Your statement is in the record in its
entirety. We ask that you summarize it in 5 minutes.
STATEMENT OF CHARLES R. BLACK
Mr. Black. Thank you, Mr. Chairman.
I appreciate the opportunity to testify here today. I am
pleased and encouraged that the committee is including coal in
its evaluation of generation options for our future.
I believe that the development of coal-based generation
options is essential to provide security of our fuel supply,
reduce volatility and fuel prices, and to provide long-term
savings in the real cost of electricity. One technology that
can help achieve these objectives is integrated gasification
combined cycle technology, commonly known as IGCC. I am here
today to share Tampa Electric's experience with IGCC technology
and our view of what is required to move IGCC to the next
level.
Tampa Electric's Polk IGCC plant was initiated in 1989. The
project was awarded funding as part of the Department of
Energy's third round of the Clean Coal Technology Program. The
plant was cited through a process using an independent site
selection committee, which recommended that this plant be cited
in an unreclaimed phosphate mine in Polk County, Florida.
By proactively working with all of our constituents, the
plant was issued all of its permits without any intervenors or
any challenges. The project was placed into service in
September 1996. And a detailed description of the technology is
provided in the written testimony that I have provided.
The Polk plant is an important part of Tampa Electric's
generation system. We depend on Polk to meet our customers'
energy needs. From our perspective, the Polk IGCC plant is a
commercial plant. The availability of Polk has increased to
about 80 percent, which is consistent with our design point for
availability.
Our Polk unit has operated reliably and efficiently for
almost 7 years. We have demonstrated over 15 types of coal as
well as blends of petroleum coke and biomass. At Tampa
Electric, we continue to rely on IGCC technology to effectively
produce electricity from coal.
IGCC technology benefits include extremely high fuel
flexibility, superior environmental performance. The technology
is well-suited for CO2 and mercury removal. It also
has the potential for higher cycle efficiencies than other
coal-fired technologies.
While Polk has demonstrated many of the technology's
advantages, barriers still remain before broader
commercialization of the technology can occur. Some of these
barriers include: the technology's high capital cost, high
operations and maintenance cost, the perceived technical
complexity of the plants, a perception that IGCC has lower
availability relative to other coal options, and uncertain
future environmental regulations. I believe the Department of
Energy can play a key role in overcoming these barriers.
The Department of Energy's role in the Polk project has
demonstrated the effectiveness of public and private
partnerships. Specific funding of technology development can be
executed effectively using these public-private partnerships.
New funding specifically for IGCC technology development should
be done in a comprehensive way, addressing both specific
technology development as well as integrated demonstration
facilities.
I believe such a comprehensive approach can help to resolve
both the technical and the financial issues associated with
IGCC. Successful development of IGCC technology will form a
good foundation for an integrated approach to maintain coal as
a viable option for producing electricity in our future.
Thank you again, Mr. Chairman, for the opportunity to be
here today and offer our thoughts. I would be glad to address
any questions.
[The prepared statement of Charles R. Black follows:]
Prepared Statement of Charles R. Black, Vice President, Energy Supply,
Engineering & Construction, Tampa Electric Company
Mr. Chairman, on behalf of Tampa Electric Company, we appreciate
the opportunity to testify at this important hearing. Coal is an
important part of our nation's electricity generation mix, and we
support the Committee's review of future options for the use of coal.
HISTORY:
Tampa Electric Company planned, engineered, built, and operates the
Polk Power Station Unit #1 Integrated Gasification Combined Cycle
(IGCC) Power Plant. The project was partially funded under the U.S.
Department of Energy's (DOE) Clean Coal Technology Program pursuant to
a Round III award. This project demonstrates the technical feasibility
of commercial-scale IGCC technology.
Tampa Electric Company began taking the Polk Power Station from a
concept to a reality in 1989. The project received an award under Round
III of the DOE Clean Coal Technology Program in January 1990 based on
older gasification and combined cycle technology to be located at a
different site. The project concept was soon revised to incorporate
newer more efficient gasification and combined cycle technology.
Meanwhile, an independent site selection committee consisting of
community representatives selected the current site, which was an
abandoned phosphate mine in southwestern Polk County Florida. The DOE
Cooperative Agreement was modified in March 1992 to incorporate these
improvements. Detailed design began in April 1993, permits were issued
without intervention, and site work began in August 1994. The power
plant achieved ``first fire'' of the gasification system on schedule in
July 1996. The unit was placed into commercial operation on September
30, 1996. Since that time, the plant has met its objective of
generating low-cost electricity in a safe, reliable, and
environmentally acceptable manner. The plant continues to operate base
loaded as a key part of Tampa Electric Company's generation fleet.
PLANT DESCRIPTION:
Polk Power Station is a nominal 250 MW (net) IGCC power plant,
located southeast of Tampa, Florida in Polk County. The power station
uses an oxygen-blown, entrained-flow coal gasifier integrated with gas
clean-up systems and a highly efficient combined cycle to generate
electricity with significantly lower SO2, NOX,
and particulate emissions than existing coal-fired power plants.
The air separation unit (ASU) cryogenically separates ambient air
into its major constituents, oxygen (O2) and nitrogen
(N2). Most of the O2 (approximately 2175 tons per
day at 96% purity) is needed in the gasification plant for the
production of fuel gas. 2.5% of the available O2 is used in
the sulfuric acid plant. Most of the N2 goes to the power
plant's combustion turbine to dilute the fuel gas for NOX
abatement. This diluent N2 also increases the combustion
turbine's power production by 15% (25 MW) as it expands through the
turbine.
The gasification plant produces clean medium BTU fuel gas and high-
pressure steam for electricity production from 2500 tons per day of
coal combined with other solid fuel such as petroleum coke and biomass.
Coal from the 2 silos on-site is mixed with recycled water plus fines
and ground into a viscous slurry which is pumped to the gasifier. The
gasifier is a Texaco slurry fed, O2 blown, entrained
gasifier operating between 2400 deg.F and 2700 deg.F. High pressure
steam is produced by cooling the syngas in a radiant syngas cooler and
two parallel fire tube convective syngas coolers. Particulates are
removed in an intensive water-scrubbing step. The gas is then further
cooled in a way that almost all of the remaining heat is recovered by
preheating the clean syngas fuel and boiler feedwater. This improves
the plant's overall efficiency. Finally, the sulfur is removed from the
gas by first converting any carbonyl sulfide compounds to hydrogen
sulfide. The hydrogen sulfide is then removed by a circulating amine
(MDEA) solution, and the clean gas is reheated, filtered, and delivered
to the combustion turbine. The sulfur removed from the syngas is sent
to the sulfur recovery system, which generates medium pressure steam
and produces 200 tons per day of 98% sulfuric acid, which is sold to
the local phosphate industry. Fines containing unconverted carbon from
gasification are separated from the slag and water and are recycled to
the slurry preparation section. The slag can be sold as aggregate for
shingles and blasting media or for use in cement manufacture. Dissolved
solids are removed from the zero discharge process water system in a
brine concentration unit so the water can be recycled.
The power block is a General Electric combined cycle, slightly
modified for IGCC. The combustion turbine is a GE 7F which generates
192 MW on syngas plus diluent N2 or 160 MW on distillate
fuel. A heat recovery steam generator (HRSG) uses the 1065 deg.F
combustion turbine exhaust gas to preheat boiler feedwater, generate
about \1/3\ of the plant's high pressure steam (\2/3\ comes from the
gasification plant's high temperature heat recovery section), generate
low pressure steam for the gasification plant, and superheat and reheat
all the plant's steam for the steam turbine.
The gross power production is typically 315 MW (192 from the
combustion turbine and 123 from the steam turbine). The oxygen plant
consumes 55 MW, and other auxiliaries require 10 MW, so the net power
delivered to the grid is 250 MW.
PLANT PERFORMANCE:
The Polk Power Station IGCC Project has met the key objectives of
the plant owner/operator and the Department of Energy since beginning
operation in 1996. Multiple technologies from many different suppliers
were successfully combined into a highly integrated efficient power
generation plant. Synthesis gas is used to fuel an advanced combustion
turbine without adverse effects. Multiple coals and other low cost
solid feedstocks have been successfully utilized. Very low emissions
are being achieved with these solid fuels. After overcoming several
initial problems, the unit is now demonstrating good availability.
Low air emissions, while using low cost solid fuel feedstocks, is
the main driver for IGCC technology. Polk's emissions of
SO2, NOX and particulates are lower than other
coal fired options. SO2 removal is typically 98% with
emissions at 0.06 lb/mwh. NOX emissions have recently been
reduced by the addition of syngas saturation and are currently
averaging 10 ppmvd corrected to 15% O2. Particulate
emissions are extremely low at 0.04 lb/mwh.
SOX and particulates are more effectively removed in
IGCC than in conventional coal combustion systems since the pollutants
are removed from IGCC's high-pressure fuel gas stream rather than from
the exhaust gas generated by total combustion. Removal of pollutants
from the fuel also makes the removal of trace elements such as mercury
more feasible and cost effective. IGCC plants are currently more
efficient than other coal technologies and their CO2
emissions are correspondingly lower. Should CO2 capture and
sequestration be called for, IGCC will have a significant advantage
since CO2 can be removed from the fuel stream prior to
combustion.
The reliability and availability of Polk's IGCC unit has improved
steadily since entering commercial service. The unit had some problems
with heat exchangers and other items that led to lower than expected
initial reliability. These problems have been addressed and the
availability of the gasifier now in the 80% range, which is consistent
with its design. Polk's gasifier availability is somewhat lower than
would be expected for the next generation IGCC plant due to the lack of
redundancy of some critical equipment. The combined cycle portion of
the plant can also be operated on distillate oil. This capability to
run on a back up fuel, increases the overall availability of the unit
to the mid 90% range which is better than any single fuel, coal fired
technology. Availability information is presented in the chart below.
The efficiency of Polk's IGCC unit, or heat rate, is approximately
9,500 btu/kwh on a steady state basis which is better than most other
coal fired technologies. Other IGCC units are even more efficient. The
Polk gasfier loses some efficiency due to lower than expected carbon
conversion and changes in heat exchanger configuration. Both of these
issues would be addressed in the next generation IGCC plant.
The cost to construct the Polk IGCC unit was about $2000/kW net of
DOE funding. This is somewhat higher than future plants since it was
one of the first of its kind. Today's direct cost for a new single
train 250 MW IGCC plant on the Polk site in Polk's current
configuration incorporating all the lessons learned is estimated to be
about $1650/kW. A new plant built with economies of scale could reduce
capital costs to $1300/kW or below. This is significantly higher than a
natural gas combine cycle plant. The cost of fuel however is much lower
for IGCC.
HOW IS IGCC CURRENTLY PERCEIVED:
The IGCC demonstration project at Polk Power Station has attracted
a great deal of attention from industry, government and academia. Since
it's inception, the plant has hosted over 2500 visitors from over 20
countries. The reason for the interest in the project is varied, but
typically focuses on the technology used, environmental performance,
system reliability and capital cost.
Many of our visitors are in the process of evaluating IGCC as an
option for generation expansion. Their interest stems from the
advantage of using coal, or other solid feedstocks, as a secure, low
cost, fuel for power generation. The IGCC process achieves the use of
coal in an environmentally acceptable manner.
Typical conclusions as to the benefits of IGCC include:
Polk has demonstrated the flexibility of using a number of
different solid fuels including over 15 coal types, petroleum
coke and biomass. This is seen as a major advantage over
natural gas from a price, volatility and security of supply
standpoint.
Polk has demonstrated superior environmental performance
regarding SO2, NOX, and particulate
matter versus other coal technologies.
IGCC is well suited for mercury and CO2 removal.
Polk has demonstrated the use of IGCC in a commercial size for
power generation.
IGCC generally has a higher cycle efficiency than other coal
fired technologies.
The typical concerns regarding IGCC technology include:
IGCC has a high level of capital investment required versus
Natural Gas Combined Cycle (NGCC) plants. There is general
agreement that capital costs will be lower for the next
generation of IGCC, but the uncertainties of returns in future
power markets have made it difficult for potential users to
select the high capital cost option.
The environmental superiority of IGCC is financially
unrewarded. Other coal-fired technologies may be able to meet
current environmental regulations and there is no economic
benefit for the additional environmental performance of IGCC.
The potential benefits of future mercury and CO2
removal are difficult to monetize.
Existing IGCC plants have been engineered and constructed as
an assembly of individual process units. The process unit
suppliers will offer performance guarantees at their boundary
limits, but no guarantee is typically available for the overall
IGCC plant. The assumption of the overall plant performance
risk has made financing and ultimately the selection of IGCC
technology more difficult.
There is the perception that IGCC has a lower equipment
availability than NGCC and perhaps other coal fired
technologies. As a demonstration plant, Polk's availability has
been lower than the next generation plant would be. Based on
the lessons learned here and at other demonstration plants, the
next IGCC plants will incorporate improvements in equipment/
material selection, operating procedures and level of
redundancy. An important point, which is undervalued by many is
that the overall availability of the plant, including operation
on backup fuel in combined cycle mode, is very high. Gasifier
availability can be engineered to be as high as the particular
project economics dictate.
Operation of an IGCC plant requires different technical skills
than those with which power-generating utilities are generally
familiar. The Polk project has demonstrated that a modest size
utility, with expertise in coal-fired generation, can build and
operate an IGCC plant. Tampa Electric paid careful attention to
personnel selection and training to make this project a
success.
A common position taken by other electric utilities is that they
would like to see someone else take the risk in building the next IGCC
plant. The ``risk'' being quoted seems about equally split between a
perceived availability risk and an economic risk. We believe that the
demonstration plants, including Polk, have shown that the availability
issue can be effectively managed, particularly in the next generation
of plants. The economic risk is a bit more complicated. The higher
initial costs for IGCC can be offset by long-term fuel savings. In the
last few years, a litany of external factors such as deregulation,
power market pricing, California, ENRON and most recently stock
devaluation have impacted the risk tolerance of potential users. At
this point, it seems everyone would like to see multiple successful
IGCC plants in service before they move forward.
STEPS NECESSARY TO MOVE FORWARD:
The DOE has been, and continues to be, very supportive of IGCC
process. Numerous programs being discussed envision IGCC as a key core
technology. Polk Power Station is an outstanding example of how IGCC
has been taken from concept to commercialization through a public/
private partnership. Tampa Electric believes strongly in the value of
IGCC and its future. Polk is the only gasification unit currently using
coal for the generation of electricity in the country. Through this
experience, the company has learned a great deal about the feasibility
of IGCC and its future commericalization opportunities. As previously
noted, while there are great opportunities, barriers exist to moving
from the current atmosphere of perceived risk to the widespread use
envisioned by the DOE.
These barriers include:
Higher capital cost
Higher operations and maintenance cost
Perceived technical complexity
Perceived lower availability
Uncertain future environmental regulations
One path to overcome these barriers is to build on the DOE
successful application of public-private partnerships. The success and
necessity of this approach has been demonstrated at Polk. Elements of
this public-private approach must include funding for technology
development and demonstration. This funding could be provided as
grants, tax credits or other means. It is important that the funding
support a comprehensive effort addressing all aspects of the
technology. The gasifier, the capital costs associated with technology
development and, operations and maintenance costs all need to be
addressed before production incentives can be realized. In addition,
the ability of long-term financing absolutely depends on full sized
integrated demonstration plants. Public-private partnerships are the
most expedient way of taking the next steps toward commercialization of
IGCC, but funding targeted toward IGCC specifically is crucial.
A comprehensive approach, utilizing a proven public-private
partnership can provide the momentum necessary to achieve zero emission
coal-fired technology for the 21st century.
Again, Mr. Chairman, thank you for the opportunity to participate
in today's hearing.
Mr. Barton. Thank you, sir.
We now want to hear from Mr. Randall Rush, who is the Power
Systems Development Facility Director for the Southern Company.
He is in Wilsonville, Alabama. Your statement is in the record.
We ask that you summarize it in 5 minutes.
STATEMENT OF RANDALL RUSH
Mr. Rush. Thank you, Mr. Chairman.
I appreciate the opportunity to appear before you today and
talk about the future of coal and electricity generation.
America stands at a significant energy crossroad primarily
for two reasons. First, there is an increasing imbalance
between usage rates and available fossil energy resources. We
currently use natural gas to produce 17 percent of our
electricity. Yet, natural gas accounts for only 10 percent of
our known fossil energy resources. Natural gas usage is
projected to increase, but at current usage rates, we only have
an estimated 60-year supply. Coal makes up 85 percent of our
fossil energy reserves. And we have more than a 250-year
supply. But it only provides a little more than 50 percent of
our electricity. This imbalance between usage and available
resources will eventually increase the price of natural gas
directly and the price of electricity indirectly.
The second reason we stand at an energy crossroad is
because coal is seen by many as a dirty fuel. Yet, coal use for
power generation has tripled since 1970 while overall emissions
from power plants have decreased by over 30 percent. These
improvements are a direct result of the research, development,
and demonstration investment made in clean coal technologies
over the last 30 years by private industry and the Federal
Government.
Environmental standards are stringent and becoming more so.
There are increasing pressures to control CO2
emissions to address concerns many have about global warming.
DOE and industry have prepared a clean coal technology road map
that outlines what is necessary to develop technology by around
2020 to produce electricity at 10 percent above today's costs
while meeting these more stringent standards and capturing and
sequestering CO2.
Several technologies are addressed in the road map, but let
us briefly take coal gasification as an example. Of the
available technologies for converting energy from coal into
electricity, gasification is seen as the most economic if
CO2 capture and sequestration are required.
I am a strong proponent of gasification. The past 10 years
of my career have been spent developing advanced energy
systems, including new coal gasification technology. In order
to meet the 10 percent electricity cost increase goal in the
road map, the capital and operating cost of gasification must
be reduced substantially and its reliability must be increased.
Because current gasification technology does not perform
well on the high-moisture, high-ash, low-rank coals that make
up 50 percent of the U.S. and world supplies, further gasifier
development and new gasifier designs are needed. Examples of
these coals in the U.S. are lignite and much of our sub-
bituminous reserves.
Pursuing developments like these can easily consume the
careers of an entire generation of engineers and scientists. I
manage a team that has, among other things, been developing the
first truly new coal gasification technology in over 50 years.
From the first discussions about the project until today, it is
15 years. The earliest of the first-of-a-kind commercial plant
based on this technology can come on stream is 2009. So the
earliest anyone can be in a position to make a decision to
build a second plant is around 2011.
It is possible to use coal consistent with environmental
expectations while meeting the goal of a 10 percent increase in
the cost of electricity, but to reach this goal would require
$14 billion of combined Federal and industry R&D, about half
from each sector.
The Federal Government must show its commitment by taking
the lead. Without such commitment, the industry cannot justify
a significant investment because the timeframe to success is
too long. When one compares the administration's fiscal year
2004 budget request for coal R&D with the annualized needs for
Federal funds from the road map, there is a shortfall of over
$200 million. This shortfall isn't new. DOE R&D today has only
one-third the purchasing power it had in 1976. It will be
impossible to meet the goal of clean, affordable energy from
coal, including carbon capture and sequestration, if this trend
is not reversed.
EPRI recently completed an estimate of the value of future
clean coal technology development using a technique called real
options. This technique is used by several major corporations
to estimate the value of physical assets in a volatile
marketplace. As Mr. Courtright indicated, EPRI's estimate of
the value of clean coal technology to consumers was between
$360 billion and $1.4 trillion by mid century.
In summary, our secure supplies of domestic coal can
continue to be the engine that fuels the U.S. economy if we
make the investments needed to ensure the timely development of
advanced coal-based technology. But to do so will take time and
a consistent, significant investment in R&D.
We need a national consensus that allows an effective
balance among energy needs, environmental quality, economic
prosperity, and overall quality of life. This national
consensus must support expansion of all energy options,
including both energy uses, such as conservation and
efficiency, and energy sources, including fossil fuels,
renewables, and nuclear.
Thank you, Mr. Chairman.
[The prepared statement of Randall Rush follows:]
Prepared Statement of Randall E. Rush, Director, Power Systems
Development Facility, Southern Company Generation and Energy Marketing
Good afternoon Mr. Chairman and Members of the Committee. I am
pleased to appear before you to discuss Future Options for Generation
of Electricity from Coal. I am employed by the Generation and Energy
Marketing arm of the Southern Company as Director of the Power Systems
Development Facility (PSDF) located in Wilsonville, AL. Southern
Company provides electricity to 4 million customers in the Southeastern
U. S. We operate 40,000 megawatts (MW) of electric generating capacity
of which over 22,000 MW is coal-fired. Southern Company's energy
businesses include electric utilities in four states, a competitive
generation company, an energy services business, and a competitive
retail natural gas company.
The PSDF is a key national asset for ensuring continued, cost-
effective, environmentally acceptable coal use. Operation of the PSDF
is currently sponsored by the U.S. Department of Energy's (DOE) Office
of Fossil Energy / National Energy Technology Laboratory, Southern
Company; the Electric Power Research Institute (EPRI); Kellogg, Brown
and Root; Peabody Energy; The Burlington Northern and Santa Fe Railway
Company; and Siemens Westinghouse Power Corporation. Foster Wheeler
Corporation (FW) is a significant past sponsor.
DOE conceived the PSDF as the world's premier advanced coal
research and development (R&D) facility. Work there has fulfilled this
expectation. As an example, a new, more efficient, less expensive, and
potentially more reliable coal gasifier developed at the PSDF is ready
for commercial deployment. In addition, the PSDF was instrumental in
advancing the design of the FW advanced circulating pressurized
combustion concept. As a result, of work there FW changed the concept
and a proposed $400 million commercial demonstration plant was
reconfigured to avoid significant problems. Proposed future testing at
the PSDF includes, among other things, integration of gasification with
advanced air separation technology, the use of coal-derived synthesis
gas in fuel cells, and evaluation of advanced hydrogen/CO2 separation
technology. A summary of major accomplishments to date and plans for
testing during the next five years at the PSDF are contained in
Enclosure 1.
Summary of Testimony. There is a growing imbalance between the
availability of the secure domestic resources that fuel electricity
generation in the U. S. and the rates at which they are being used.
Natural gas accounts for about 10 percent of domestic energy reserves,
but is currently used to generate 17 percent of our electricity. At
current use rates natural gas reserves are projected to last
approximately 60 years, but usage is projected to increase and gas
production in the lower 48 states has not increased in over a decade in
spite of a quadrupling of exploration. On the other hand, coal accounts
for 85 percent of domestic energy reserves and generates approximately
56 percent of our electricity. At current use rates domestic coal
reserves are estimated at more than 250 years.
Natural gas is a remarkably versatile fuel and like electricity is
used extensively in residential, commercial, and industrial
applications. Coal is a less flexible fuel and is rarely used in
residential and commercial applications. Its primary current use is in
generating electricity. The continuing depletion of the natural gas
resource will eventually increase both its price and the price of
electricity. The result will be a reduction in U. S. competitiveness in
the world and in the Nation's economic well being.
Current DOE coal research, development, and demonstration (RD&D)
programs, if adequately funded, will assure that a wide range of
electric generation technology options continue to be available for
future needs. Further, the continued use of coal in an environmentally
acceptable manner will contribute to continued economic prosperity by
ensuring that both electricity and natural gas prices remain low. Prior
DOE clean coal research has already provided the basis for $100 billion
in consumer benefits at a cost of less than $4 billion (Enclosure 2).
Funding the advanced Clean Coal Technology Roadmap that industry and
DOE have jointly developed can lead to additional consumer benefits of
between $360 billion and $1.38 trillion (Enclosure 3).
There are enormous competing needs for Federal funding, but few
things go more directly to the root of economic prosperity than secure,
affordable, clean energy. The U. S. has always been the world leader in
energy research, but if the current funding trend for advanced coal-
based energy system RD&D is not reversed the U. S. will take the wrong
turn at the crossroad we face. Down that road lies increased energy
prices, increased dependence upon overseas energy supplies, and
decreased economic prosperity. The alternative is to reverse the trend
in RD&D spending for advanced coal technology and take the more
rational road toward a more secure, prosperous energy future.
Electricity is at the Core of the U. S. Economy. In fact,
electricity drives the U. S. economy. Figure 1 shows the strong
relationship over the last 30 years between the U. S. Gross Domestic
Product (GDP) and electricity use.
Electricity has been referred to by some as the currency of the
information age. It is used extensively in residential, commercial, and
industrial applications and sales nationwide are over $230 billion/
year. Consequently, the price of electricity directly affects the
competitiveness of U.S. manufactured goods in the world market, and the
Nation's economic well being.
Using Abundant Low Cost Coal for Electricity Generation Instead of
the Diminishing Supply of High Cost Natural Gas. Coal is used to
generate approximately 56 percent of the electricity in the U.S. and
accounts for 85 percent of known U. S. fossil energy resources. Coal
reserves are estimated at over 250 years at today's usage rates. With
the repeal of the Fuel Use Act in 1987 an ever increasing amount of our
electricity has been generated from natural gas. Natural gas currently
generates 17 percent of the Nation's electricity, but it accounts for
only 10 percent of known U. S. fossil energy resources. Natural gas
usage is projected to increase, but at current use rates reserves are
estimated at only around 60 years. Natural gas is a remarkably
versatile fuel and like electricity is used extensively in residential,
commercial, and industrial applications. Coal is a less flexible fuel
and is rarely used in residential and commercial applications. Its most
valuable characteristics are its domestic abundance, its ready
availability, and its low cost as a fuel source for affordable
electricity.
Current indications are that supplies of natural gas in the lower
48 States are not increasing to meet the increased demand. Figure 2
shows that in the decade since 1992 production has remained constant
despite a quadrupling of drilling rigs.
As shown in Figure 3, two consequences of this flat production have
been significant short-term increases in natural gas prices (reaching
to near $10.00/MBtu) combined with a substantial increase in its long-
term price trend. These trends are expected to continue. Coal's price
has remained steady during the same period that natural gas prices have
been volatile and coal's long-term price is projected to remain below
$1.50/MBtu well into the future.
This increasing imbalance between the Nation's usage rates and
available resource levels of natural gas and coal has major long-term
consequences. Because natural gas has become a significant fuel for
electricity generation the continuing depletion of the natural gas
resource will eventually increase its price directly and the price of
electricity indirectly.
Coal is Wrongly Perceived as a Dirty Fuel. Figure 4 shows that
although coal use for power generation has tripled since 1970, overall
emissions from power plants have decreased by over 30 percent. Further
reductions are expected within the next 5 to 10 years as additional
technology required under the 1990 Clean Air Act is brought into
service. These improvements are a direct result of the RD&D investment
made in clean coal technologies over the last 30 years by private
industry and the Federal government.
The coal used in electricity production is a major source of the
carbon dioxide (CO2) emissions that are seen as a significant
contributor to global warming. Currently available coal-based
technology cannot simultaneous fulfill the objectives of providing low
cost electricity and achieving near zero-emissions (including carbon
dioxide). However, our secure supplies of domestic coal can continue to
be the engine that fuels the U. S. economy, if as a Nation, we will
make the RD&D investments needed to ensure the timely development of
acceptable coal-based technology.
Coal is an abundant fuel throughout the world. It fuels more than
one-third of global electricity production, and growth in energy demand
is particularly strong in coal-dependent areas such as China and India.
The increase in coal use expected in the U.S. in the next few decades
is dwarfed by the increase in coal use expected in other countries.
Over the next 30 years, China and India alone are expected to account
for two-thirds of the increase in total world coal demand, principally
for electricity generation. Advanced technologies that allow the
economic use of coal consistent with environmental expectations have
the potential to be deployed not only in the U.S. but around the world
as well. The opportunity to deploy these technologies internationally
only heightens the need to adequately fund RD&D of advanced coal
technology.
For Coal to Remain a Viable Alternative for Electricity Generation
a Long-Term Commitment to RD&D is Needed. The Coal Utilization Research
Council 1 (CURC), EPRI, and DOE recently completed extensive
discussions that led to the creation of a common ``Clean Coal
Technology Roadmap'' that lays out specific pathways and achievable
goals for improvements in the efficiency, cost, and emissions of coal-
based energy by 2020. There are specific targets for emissions of
sulfur dioxide, nitrogen oxides, particulate matter and mercury, carbon
dioxide management, by-product use, water use and discharge,
efficiency, reliability, and cost (capital and production) that
advanced clean coal technologies can achieve over the next 20 years if
RD&D is adequately funded.
---------------------------------------------------------------------------
\1\ The CURC is an ad-hoc group of electric utilities, coal
producers, equipment suppliers, state government agencies, and
universities. CURC members work together to promote coal utilization
research and development and to commercialize new coal technologies.
Its 40+ members share a common vision of the strategic importance for
this country's continued utilization of coal in a cost-effective and
environmentally acceptable manner.
---------------------------------------------------------------------------
The Roadmap seeks to identify the critical technologies that must
be successfully developed, as well as the timelines for when that
development must take place, if our Nation is to have highly efficient,
near-zero emission, coal-base energy production facilities available
for commercial deployment by 2020. If the Roadmap is followed, by 2015
designs for high-efficiency, near-zero emission power plants can be
ready for application and by 2020 the first of these advanced plants
can be commercially introduced.
The Roadmap also identifies the RD&D cost to achieve these goals.
From now until 2010 $6.5 billion is needed with approximately $3.5
billion needed over the following decade. Further, it is estimated that
an additional $4 billion will be required by 2020 for extensive carbon
sequestration research--for a total of around $14 billion. The share
between industry and government will vary among projects and phases of
development, but based on historical precedence about half of these
funds will come from industry and half from the Federal government. The
ongoing industry cost sharing in DOE research programs, numerous
projects executed under the Clean Coal Technology (CCT) program, and
the recent large response to the Clean Coal Power Initiative (CCPI)
affirm industry's willingness to fund its share of advanced energy
RD&D.
The Roadmap includes both advanced combustion-based systems and
advanced coal gasification. Both technologies need substantial
improvement before becoming a significant part of the Nation's
electricity generation capability. Take coal gasification as an
example. Gasification will be the core technology of the FutureGen
project announced recently by President Bush. Of the available
technologies for converting energy from coal into electricity,
gasification is currently seen as being the most economic if CO2
capture and sequestration are required--sequestration is the long-term
disposal of CO2 in deep underground repositories. Even so, CO2 capture
and sequestration are estimated to increase the cost of electricity
from coal gasification by 30 to 40 percent. And, gasification is
currently 5 to 10 percent more expensive than pulverized coal
technology for electricity generation. By comparison the goal in the
Roadmap is for only a 10 percent increase in the cost of electricity
while capturing and sequestering CO2. As described in the FutureGen
announcements, gasification is also projected to be the most
economically viable technology for advancing the U.S. towards the
hydrogen economy, where coal-based hydrogen fuel reduces
transportation-based carbon dioxide emissions and lowers our national
dependency on foreign oil.
In order to realize practical hydrogen production from coal and
meet the 10 percent electricity cost increase goal, the capital and
operating cost of gasification must be reduced substantially and its
reliability must be increased. Specifically, the reliability of
equipment in the power generation train must increase to the near 100
percent levels typical of current power generation technology. This
will require improved materials of construction and temperature
measurement instrumentation, improved fuel rate monitoring technology
and increased fuel injector life. In addition, less expensive gas
cleaning technology (including CO2 and hydrogen separation systems)
that can handle multiple contaminates must be developed. The cost of
air separation technology must be lowered by at least 25 percent. Coal
preparation and feed systems for high pressure environments must be
substantially improved. And, because the current commercial
gasification technology does not perform well on the high moisture,
high ash, low rank coals that make up 50 percent of the U. S. and world
coal reserves, further gasifier development and new gasifier designs
are needed.
The world's scientists and engineers have only recently turned to
solving these problems. With increased attention in the technical
community these goals can be met. But, it takes time and money and
without sufficient funding it will take even more time.
Southern Company estimates that past DOE research related to large-
scale, coal-based power generation will provide over $100 billion in
benefits to the U.S. economy through 2020 at a Federal cost of less
than $4 billion--a benefit cost ratio of 25 to 1 (Enclosure 2). EPRI
recently used the modern financial technique called ``Real Options'' to
estimate the value of advanced coal RD&D 2. The major
conclusion is that the value to U. S. consumers of further coal RD&D
for the period 2007-2050 is at least $360 billion and could reach $1.38
trillion (Enclosure 3).
---------------------------------------------------------------------------
\2\ Market-Based Valuation of Coal Generation and Coal R&D in the
U.S. Electric Sector, May 2002, EPRI-LCG.
---------------------------------------------------------------------------
The technique of real options analysis is being used increasingly
by businesses to assess investments in physical assets, particularly in
fluctuating markets. Leaders include Chevron, Hewlett Packard (Business
Week, June 7, 1999), Shell and IBM. Also discussed in: ``Real Options:
A better way to make decisions about power plants'', Global Energy
Business, March/April 2001.
However, the long-term nature of the necessary RD&D program and
high risk associated with it means that industry cannot afford to make
this investment alone. The Real Options analysis also showed that
industry as a whole cannot justify investing more than $5-6 billion on
advanced coal-based energy technology development. The cost and time
scales are simply too large for individual companies or even individual
industries to make significant progress alone. Moreover, the major
beneficiaries of improved coal-based energy systems are consumers.
The Real Options analysis makes it clear that major public
investment designed to supplement private investment in advanced clean
coal technology can provide significant economic benefits to consumers,
but the Federal government must take the initiative. However, the trend
in Federal RD&D funding is disappointing. In real dollars, the amount
the Federal government currently spends on advanced coal research is
only a third of that spent in 1976. As an example, the Roadmap calls
for $500 million in annual Federal funding for RD&D of coal-based
energy systems. Actual annual appropriations fall short of this figure
by more than $200 million.
There are enormous competing needs for Federal funding, but few
things go more directly to the root of economic prosperity than secure,
affordable, clean energy. If current funding trends for advanced coal-
based energy systems are not reversed the U. S. will take the wrong
turn at the crossroad we face. Down that road lies increased energy
prices, increased dependence upon overseas energy supplies, and
decreased economic prosperity. The alternative is to reverse the trend
in Federal RD&D spending for advanced coal technology and take the more
rational road toward a secure, prosperous energy future.
Mr. Barton. Thank you, Mr. Rush.
We now want to hear from Mr. Dick Olliver, who is the Group
Vice President for Global Energy Incorporated, White House
Station, New Jersey. Your statement is in the record. We ask
that you summarize it in 5 minutes.
STATEMENT OF RICHARD A. OLLIVER
Mr. Olliver. Thank you, Mr. Chairman.
Global Energy is pleased to have the opportunity to testify
on the important topic of future options for generation of
electricity from coal.
Global Energy is an independent international energy
company with a primary strategy of utilizing gasification
technology in the development of its own power generation
projects or licensing our proprietary technology to others. We
are the owner and licensor of E-GAS gasification technology,
originally developed by Dow Chemical. Additionally, we own and
operate the Wabash River Limited gasification facility in Terre
Haute, Indiana, which since 1995 has gasified high-sulfur coal
and petroleum coke using the E-GAS process, providing synthesis
gas and steam to our neighbor utility, Cinergy, for the net
production of 262 megawatts of electricity. Of significance to
this hearing, Wabash River Energy is the cleanest coal-fired
power plant in the world.
Global Energy is a member of the Gasification Technologies
Council, the preeminent trade association of the gasification
industry. I currently serve as a member of the Board of
Directors of the GTC and recently served as Chairman of the
organization. The GTC members provide technologies for
gasification, industrial gas supply, gas cleanup and
conditioning, sulfur recovery, power generation and others, as
well as equipment and technical services. These components form
the core of industry know-how of current and future
gasification-based power, fuels, and chemical plants in the
U.S. and around the world.
Reflecting again on the Wabash River gasification facility,
I request that the comments of my Global Energy colleague, Mr.
Phil Amick, be included with my written statement for this
hearing.
The Wabash River project was a repowering using
gasification of a 1953 vintage pulverized coal plant and
resulted in dramatic reductions of SOX,
NOX, PM10, and CO2 emissions.
The Wabash River facility and the Tampa Electric Polk power
station in Florida are the first of a new class of coal-based
electrical generation plants with superior environmental
performance compared to other technologies such as pulverized
coal and fluidized bed boilers. Wabash River has been operating
since 1995 with emissions lower than coal-based power plants
that are now being permitted for operation in 2005.
Accordingly, it is our strong belief, pertinent to the subject
of this hearing, that coal gasification is ready today as a
clear and worthy option for power generation in North America.
E-GAS and other prominent coal gasification technologies
described here today, have already been successfully
demonstrated in power generation modes as well as for
commercial production of chemicals and are ready to be
implemented in the next round of power plant capital expansion.
Recently I reviewed the public record of other hearings
held by your committee relative to today's topic. We commend
the committee and this subcommittee on their vision and
initiatives to highlight and increase public awareness of
important related topics, including national energy policy,
hydrogen, and natural gas issues.
Remarks made before this committee on March 14, 2001 by
Richard Abdoo of Wisconsin Energy outlining four basic
principles of energy policy for power generation emphasized the
use of domestic resources, particularly coal, for power
generation. His comments are perhaps more profound today as the
problems of energy supply have, in fact, become more acute,
presenting immediate and serious threats to our economy and
national security. To amplify this point, I request that a copy
of the article in The Wall Street Journal, article of June 18,
2003, titled ``Gas Prices Rock Chemical Industry,`` be included
with my written statement.
Similarly, on June 10, 2003, during this subcommittee's
hearing on natural gas supply and demand, the honorable Alan
Greenspan described today's reality in the U.S. of tight
supplies of natural gas along with sharply rising prices and
identified new capacity of imported LNG as a promising
mechanism for ``creating a price-pressure safety valve`` and
improved ``widespread natural gas availability in North
America.`` While we agree that LNG is indeed a worthy option to
the natural gas supply issue, we strongly suggest that coal
gasification be added to the list of worthy solutions.
It is noteworthy that coal gasification is in a state of
commercial readiness today, thanks to the vision and support of
the U.S. Congress and the Department of Energy initiating and
implementing valuable programs including clean coal technology,
Vision 21, Clean Coal Power Initiative, and others, along with
the enthusiastic participation of private industry and public
utilities.
Accordingly, we wholeheartedly commend and extend continued
support for the DOE programs embracing coal gasification for
power and consistent with Vision 21 for the co-production of
chemicals and other products.
Specifically on the topic of FutureGen, we commend----
Mr. Barton. Could you summarize very quickly? You are about
a minute over.
Mr. Olliver. We fully support the FutureGen program for
DOE. And I ask that our letter from the GTC be included as a
matter of record with my testimony.
Mr. Barton. Without objection.
Mr. Olliver. This concludes my remarks. Thank you very much
and look forward to questions.
[The prepared statements of Richard A. Olliver and Phil
Amic follow:]
Prepared Statement of Richard A. Olliver, Group Vice President, Global
Energy, Inc.
Mr. Chairman. Global Energy is pleased to have the opportunity to
testify on the important topic of ``Future Options for Generation of
Electricity from Coal.''
Global Energy is an independent international energy company with a
primary strategy of utilizing gasification technology in the
development of its own power generation projects, or licensing our
proprietary gasification technology to others. We are the owner and
licensor of E-GAS TM Gasification Technology, originally
developed by Dow Chemical. Additionally, we own and operate the Wabash
River Ltd. gasification facility in Terre Haute, Indiana, which since
1995 has gasified high sulfur coal and petroleum coke using the E-GAS
TM process, providing synthesis gas and steam to our
neighbor utility, Cinergy, for the net production of 262 MW
electricity.
Of significance to this hearing, Wabash River Energy is the
cleanest coal-fired power plant in the world.
Global Energy is a member of the Gasification Technologies Council
(GTC), the pre-eminent trade association of the gasification industry.
I currently serve as a member of the Board of Directors of the GTC, and
recently served as Chairman of the organization. The GTC members
provide technologies for gasification, industrial gas supply, gas
cleanup and conditioning, sulfur recovery, power generation and others,
as well as equipment and technical services. These components form the
core of ``industry know-how'' of current and future gasification-based
power, fuels, and chemical plants in the U.S. and around the world.
Reflecting again on the Wabash River gasification facility, I
request that the comments of my Global Energy colleague, Mr. Phil
Amick, be included with my written statement for this hearing. Wabash
River is a repowering of a 1953 vintage pulverized coal plant, one that
was operating on compliance coal, and had precipitators but was
unscrubbed. Compared to the performance prior to the repowering, based
on 1990 data for the older plant, the new facility makes almost six
times as many megawatt hours of electrical power, yet reduces emissions
of SOX by over 5500 tons per year, NOX by 1180
tons per year, and PM10 particulates by 100 tons per year.
It produces 20% less CO2 per megawatt of production because
it is 20% more efficient than the original plant.
Mercury removal is about 50%, through the cleanup processes for
other pollutants. An IGCC facility can be designed for up to 95%
mercury removal.
The Wabash River facility, and the Tampa Electric Polk Power
Station in Florida, are the first of a new class of coal-based
electrical generation plants with superior environmental performance
compared to other technologies such as pulverized coal and fluidized
bed boilers. Wabash River has been operating since 1995 with emissions
lower than coal-based power plants that are now being permitted for
operation in 2005.
Accordingly, it is our strong belief, pertinent to the subject of
this hearing, that Coal Gasification is ready today, as a clear and
worthy option for power generation in North America. E-GAS
TM and other prominent coal gasification technologies
described here today, have already been successfully demonstrated in
power generation modes, as well as for commercial production of
chemicals, and are ready to be implemented in the next round of power
plant capital expansion.
In preparation for this hearing, I reviewed the public record of
other hearings held by your committee relative to today's topic. We
commend the Energy and Commerce Committee and this sub-committee on
their vision and initiatives to highlight and increase public awareness
of the important related topics including Comprehensive National Energy
Policy, The Hydrogen Economy, and Natural Gas Supply and Demand Issues.
In that regard, it bears repeating today excerpts from the
statement made before this Committee on March 14, 2001 by Richard Abdoo
of Wisconsin Energy, outlining four basic principles of energy policy
for power generation:
A balance of economic, environmental and energy supply goals
A need for fuel diversity
A commitment to long-term solutions
An emphasis on domestic resources--particularly coal
These observations are perhaps more obvious and more important
today as the problems of energy supply have in fact become more acute,
presenting immediate and serious threats to our economy and national
security. To amplify this point, I request that a copy of the article
in The Wall Street Journal of June 18, 2003, titled ``Gas Prices Rock
Chemical Industry'', be included with my written statement for this
hearing.
One of the current concerns discussed by this committee on June 10,
2003, highlighted Natural Gas Supply and Demand Issues. On that
occasion, the Honorable Alan Greenspan described today's reality in the
U.S. of tight supplies of natural gas along with sharply rising prices,
and identified new capacity of imported LNG as a promising mechanism
for ``creating a price-pressure safety valve'' and improved
``widespread natural gas availability in North America''.
While we agree that LNG is indeed one viable and worthy option to
the ``natural gas supply issue'', we strongly suggest that Coal
Gasification be added to the list of viable and worthy solutions.
It is noteworthy, that Coal Gasification is in a state of
commercial readiness today in this time of obvious need, thanks to the
vision, commitment and support of the U.S. Congress and the Department
of Energy (DOE), initiating and implementing valuable programs
including Clean Coal Technology, Vision 21, Clean Coal Power
Initiative, and many others, along with the enthusiastic participation
of private industry and public utility entities.
Accordingly, we whole-heartedly commend and extend continued
support for the DOE programs aimed at furthering and improving the use
of Coal Gasification for power generation, and consistent with DOE
Vision 21, for co-production of chemicals and other useful commercial
by-products.
Specifically on the topic of FutureGen, we commend the DOE for
proposing this bold initiative which recognizes that Coal Gasification
must provide the technological foundation for the U.S. power generation
industry, if coal is to have a long-term future in this arena.
Furthermore, I request that the comments recently submitted by the GTC
on the proposed FutureGen project be included with my written statement
for this hearing.
This concludes my remarks. I thank you for the opportunity to
appear before this Committee and would be pleased to answer questions.
______
Prepared Statement of Phil Amick, Vice President, Commercial
Development, Global Energy, Inc.
My name is Phil Amick and I am Vice President, Commercial
Development for Global Energy Inc., headquartered in Cincinnati, Ohio.
I would like to thank the Chairman and the other members of the
Subcommittee for allowing me to submit this statement for this hearing.
Global Energy owns and operates the Wabash River Energy Ltd.
gasification facility in Terre Haute, Indiana. The affiliated power
generation plant is owned and operated by Cinergy. This 262 MW facility
powers about 250,000 homes while utilizing local high sulfur coals, and
even petroleum coke feedstocks, with sulfur content of 5.5% and more.
More to the point for this hearing, it is the cleanest coal fired power
plant in the world, of any technology.
The Wabash River IGCC is a repowering of a 1953 vintage pulverized
coal plant, one that was operating on compliance coal and had
precipitators but was unscrubbed. Compared to the performance prior to
repowering, based on 1990 data for the older plant, the new facility
makes almost six times as many megawatt hours of electrical power yet
has reduced emissions of SOX by over 5500 tons per year,
NOX by 1180 tons per year and PM10 particulates
by 100 tons per year.
The Wabash facility, and the Tampa Electric Polk Power Station in
Florida, are the first of a new class of coal-based electrical
generation facilities with superior environmental performance compared
to other technologies such as pulverized coal and fluidized bed. Wabash
has been operating since 1995 with emissions lower than coal plants
that are now being permitted for operation in 2005.
Wabash is a power plant using high sulfur coal that has
SO2 emissions as low as one fortieth of the Clean Air Act
Year 2000 standard. Sulfur is chemically extracted from the syngas and
sold for use in the fertilizer industry, about a railcar per day of
pure sulfur that used to go into the atmosphere.
It's a coal power plant where the coal ash products emerge as a
vitrified black sand byproduct and are marketed as construction
material. There are no solid wastes from the coal gasification
process--no scrubber sludge, fly ash or bottom ash.
In this plant, the wastewater stream from the chemical process
meets current National Drinking Water Standards.
Carbon dioxide emissions are 20% lower than conventional unscrubbed
coal fired plants because of the inherent efficiency of the
gasification combined cycle process. The plant, with no additional
special equipment, also has a mercury removal rate of about 50%.
One of the keys to this superior environmental performance is the
fact that the gasification process takes place at high pressure. This
facilitates the chemical processes that remove the pollutants.
High pressure operation also will facilitate additional carbon
reduction and mercury removal measures on future plants. Department of
Energy and industry studies indicate that significant reductions can be
achieved with much less cost and performance impact than possible with
coal combustion technologies that operate near atmospheric pressure.
While carbon dioxide emissions already 20% less than conventional
units, this emission can be reduced more than 75% by shifting the
syngas to hydrogen. This technology, already in use at some hydrogen
production facilities, can be retrofit to a gasification facility for
as little as 2 % of the original capital cost. The plant output
reduction for this additional process step is a fraction of what would
be seen in a conventional technology plant. In a gasification facility,
it can be retrofit at any time in the future.
Mercury removal is also much simpler in the gasification process. A
plant like the Wabash River facility could be upgraded to 80% or better
mercury removal by the addition of a single carbon bed vessel, at a
cost of less than $1 million dollars. Other facilities, such as the
Tennessee Eastman gasification plant for chemical feedstock production
in Kingsport, Tennessee, achieve better than 90% mercury removal to
meet their process constraints, and have been doing it for nearly two
decades.
Gasification technology for coal based power generation is being
commercially marketed by ourselves and others. We feel that it is the
most environmentally friendly solution for diversifying the fuel mix of
new electrical power plant capacity. Through repowering, much of the
existing, aging coal generation base can be upgraded as well, as was
done at Wabash River.
Thank you, Mr. Chairman, that concludes my oral statement. With
your permission, I have additional materials that can be included in
the record.
Mr. Barton. Thank you, Mr. Olliver.
We want to now hear from Mr. Larry McDonald, who is
Director, Design Engineering and Technology, The Babcock and
Wilcox Company in Barberton, Ohio. Your statement is in the
record. We ask that you summarize in 5 minutes.
STATEMENT OF LAWRENCE E. McDONALD
Mr. McDonald. Thank you, Mr. Chairman.
I am responsible for the design, engineering and technology
at the Babcock and Wilcox Company, a major supplier of
technologies for coal-based power plants. Approximately 40
percent of the installed coal-based electrical generation
capacity is B&W equipment. I appreciate the opportunity to
speak with you this afternoon.
Our testimony is mainly about the need for and promise of
an advanced combustion development program. A major goal of
this program would be to make it possible to capture carbon
dioxide emissions from coal combustion. This would facilitate
sequestration if or when it may be needed in response to public
policies.
From today's hearing, it should be clear that much of the
planning of government-sponsored coal-powered generation R&D is
weighted toward gasification. A major reason for this is that
IGCC systems have the ability to produce a concentrated stream
of carbon dioxide, thus enabling sequestration.
By contrast to the emerging gasification complexes, the
flue gases of conventional coal combustion power plants are
diluted with nitrogen from the combustion air. This dilution
effect is the greatest impediment to affordable separation of
carbon dioxide from the combustion plant flue gases.
Currently power generation technology providers, especially
boiler manufacturers, are developing a variety of advanced
combustion technologies to produce concentrated streams of
carbon dioxide potentially amenable to sequestration. Our
company is most actively engaged in the combustion of coal with
oxygen, rather than air. We believe that the oxygen fuel-fired
boiler approach is closest to commercialization.
Using oxygen, rather than nitrogen containing air, to burn
coal precludes the dilution of the flue gas by nitrogen. The
flue gases become largely carbon dioxide with other products of
combustion. This makes separation of a concentrated stream of
carbon dioxide much easier.
In addition to facilitating carbon management, this
approach promises an important secondary benefit. By not firing
with air, much less nitrogen is introduced into the furnace. As
a result, much less NOX may reduce the need for
additional add-on NOX controls to satisfy emissions
requirements. We have been actively working on this approach
since 1999. Currently we are conducting work at the B&W
research lab with a pilot facility that simulates full-scale
boilers.
We plan to continue development of the technology toward
full-scale system design. Presuming success with our research
and development plans, we can foresee being ready for a full-
scale demonstration around 2008.
Ultimately the marketplace will decide the technologies
that are utilized for future power generation. Our country's
interest will best be served by having available many different
responsible options. Advantages of some of the advanced
combustion systems exemplified by oxy-fuel combustion include
potential applicability to some of the existing fleet as well
as new power plants, near to mid-term availability, relative
simplicity of overall system designs, potentially lower costs
for carbon dioxide capture, and electrical generation
efficiencies comparable to current gasification systems.
Government support is warranted for the creation and
funding of a substantial development and demonstration program
in advanced combustion systems. The clean coal power initiative
provides appropriate opportunities for large-scale, first-of-a-
kind demonstrations of new technologies. CCPI program rules
should enable demonstration of a wide range of technological
approaches. Future CCPI solicitations should not be arbitrarily
weighted toward gasification, essentially impeding
demonstrations of other responsible potentially lower-cost
options.
FutureGen is intended to be a major showcase and test bed
for the combination of coal-based electricity generation,
hydrogen production, and carbon dioxide sequestration. These
are laudable goals. The planned $800 million government cost
share for the projected $1 billion total project cost is a
large commitment in an environment of severe budget
constraints. It is critical that the funding for FutureGen be
provided as additions to the DOE budget and not by reducing or
redirecting funds otherwise intended to support CCPI or other
important clean coal R&D and demonstration programs.
The development and commercial use of clean coal
technologies will enable the responsible use of coal,
addressing priority pollutants and coupled with sequestration,
greenhouse gas emissions. Timely advance in clean coal
technology will require significant cost share funding for
research and development projects and demonstrations of
emerging technology and tax incentives to reduce the risks and
encourage early development and refinement of the new
technologies.
I thank you for your attention.
[The prepared statement of Lawrence E. McDonald follows:]
Prepared Statement of Lawrence E. McDonald, Director, Design
Engineering and Technology, Babcock & Wilcox Company
Chairman Barton, Ranking Member Boucher, and members of the
subcommittee; Babcock & Wilcox Company is pleased to have the
opportunity to provide testimony for the hearing of the Energy and
Commerce Subcommittee on Energy and Air Quality on ``Future Options for
Generation of Electricity from Coal''. Our testimony is primarily
focused on the need for and potential benefits of an advanced
combustion development program as an important dimension of our
nation's approach to its energy future.
Babcock & Wilcox Company is an operating unit of McDermott
International. McDermott International, Inc. is a leading worldwide
energy services company, providing engineering, fabrication,
installation, procurement, research, manufacturing, environmental
systems, and project management for a variety of customers in the
energy and power industries, including the U.S. Department of Energy.
For over 135 years, the Babcock & Wilcox Company has earned a
reputation of excellence, setting the standards for the power
generation industry and supplying innovative solutions to meet the
world's growing energy needs. With power generation systems and
equipment found in more than 800 utilities and industries in over 90
countries, we are truly powering the world. More than 10,800 employees
around the globe make up the B&W team. And because of our forward-
thinking, talented and dedicated employees, we continue to reach new
levels of success.
SUMMARY
A primary technical impediment to sequestration of exhaust gases
from conventional coal-fired power plants is the dilution of the flue
gases by the nitrogen that is contained in the combustion air that is
supplied to the boilers. Air is about 21 percent oxygen, which is
needed for combustion of the coal, and about 78 percent nitrogen.
Development efforts are envisioned and/or underway by boiler technology
suppliers to define practicable ways to create, through advanced
combustion systems, concentrated streams of carbon dioxide from flue
gases--thus facilitating subsequent sequestration if/when needed to
respond to public policy imperatives.
Babcock & Wilcox Company is exploring a variety of alternatives to
produce concentrated streams of carbon dioxide from coal combustion
systems; and is most actively engaged in oxy-fuel boiler system
development. Through studies and pilot scale tests conducted to date,
we are encouraged that the oxy-fuel system will be ready for large
scale demonstration around year 2008. Assuming success, the concept
would benefit new power plants and potentially have some application to
the fleet of existing power plants.
The U.S. economy will be favorably served by maintaining a variety
of energy supply options. The government's coal power plans for the
future are predominantly based on the presumption that gasification
approaches will be the most viable options. It is possible that many of
the gasification-related RD&D initiatives, such as FutureGen, will
prove to be valuable. On the other hand, the variety of attributes of
oxy-fuel combustion and other coal combustion based approaches leads us
to anticipate greater potential marketplace viability for advanced
combustion technologies. Advantages of some of the advanced combustion
systems, exemplified by oxy-fuel combustion, include potential
applicability to the existing fleet as well as new plants, near- to
mid-term availability, relative simplicity of overall system designs,
lower costs for capture of carbon dioxide, and comparable electricity
generation efficiencies to gasification systems. Government support is
warranted for the creation and funding of a substantial development and
demonstration program in advanced combustion systems.
GENERAL COMMENTS
U.S. economic growth depends upon low cost plentiful supplies of
energy, which can best be achieved through an energy marketplace with a
variety of responsible options.
Coal will continue to be a major part of the energy supply mix for
many decades to come. It makes up 90 percent of our domestic energy
reserve, and 90 percent of the coal mined is used to generate
approximately 50 percent of the electricity used in the country today.
We are gratified that there is a growing recognition that coal will
continue to be a major fuel source for our nation's electrical
generation for the foreseeable future.
Energy policies are likely to be affected by increasing priorities
on carbon management. The challenges of natural gas availability,
reserve depletion, prices, and price volatility are well known.
Policies that encourage fuel switching to natural gas from the higher
carbon content coal for generation may not be in the best interest of
our country.
The development and commercial use of clean coal technologies will
enable the responsible use of coal; addressing priority pollutants and,
coupled with sequestration, greenhouse gas emissions. Timely advances
in clean coal technology will require significant cost-shared funding
for research and development projects and demonstrations of emerging
technology, and tax incentives to reduce the risks and encourage early
deployment and refinement of the new technologies. These issues are
addressed by industry groups such as the Coal Utilization Research
Council and Electric Power Research Institute.
Regarding carbon management technologies, until recently,
approaches to carbon dioxide reductions in coal fired electrical power
generation have been mainly focused on efficiency improvements; i.e.,
producing more electricity from each unit of coal burned, through
development of advanced steam cycles with higher operating pressures
and temperatures, improved operating controls, etc. This important
cross-cutting work needs to continue.
Much of the focus of government funded R&D for the future
utilization of coal is weighted toward gasification. A principal
attribute associated with integrated gasification combined cycle is the
ability of the system to produce a concentrated stream of carbon
dioxide, thus enabling sequestration. Gasification offers considerable
potential, however, there are significant technological and economic
hurdles that must be overcome in order to realize the benefits of these
complex systems.
Currently, power generation technology providers, especially boiler
manufacturers, are focusing on developing advanced combustion
approaches that would also produce concentrated streams of carbon
dioxide potentially amenable to sequestration. The efforts to develop
combustion alternatives to gasification create a dynamic scene; some of
the advanced combustion systems are being defined and still others are
emerging. Babcock & Wilcox is actively engaged in advanced combustion
approaches which we are cautiously optimistic will prove to be viable
options for concentration and capture of carbon dioxide in the near to
mid term future. Some of the approaches should potentially be
applicable to some of the existing power generation fleet as well as
new facilities.
The Coal Utilization Research Council, through its road-mapping
process has determined that an Advanced Combustion Program needs to be
an important part of the DOE's fossil energy R&D program. This has been
conveyed to Congress and to the DOE. It is imperative that a suite of
technologies be developed and that the marketplace be allowed to decide
which are best suited based on site and economic conditions.
We offer the following comments on the major planned demonstration
programs, namely the Clean Coal Power Initiative and FutureGen.
The Clean Coal Power Initiative provides appropriate opportunities
for large-scale, first-of-a-kind demonstrations of new technologies.
CCPI program rules should enable demonstration of a wide range of
technological approaches. Future CCPI solicitations should not be
arbitrarily weighted toward gasification, essentially impeding
demonstrations of other responsible options.
FutureGen is intended to be a major showcase and testbed for the
combination of coal-based electricity generation, hydrogen production,
and carbon dioxide sequestration. These are laudable goals. The planned
$800 million government cost share for the projected $1 billion total
project cost is a large commitment in an environment of severe budget
constraints. By way of comparison, the entire CCPI demonstration
program will require $2 billion in government cost shares over its
entire 10-year duration, presuming full funding. It is critical that
funding for FutureGen be provided as additions to the DOE budget; and
not by reducing or redirecting funds otherwise intended to support CCPI
or the other important clean coal research, development, and
demonstration programs.
Ultimately, the marketplace will decide the technologies that are
utilized, and we repeat that our country's interests will be best
served by providing many different responsible options. As the National
Coal Council stated in its May 2003 report ``Research And Development
Needs And Deployment Issues For Coal Related Greenhouse Gas
Management'', ``. . . Given the time before wide-scale sequestration is
likely to be practiced, there is an opportunity to explore a wide range
of potential capture options, applicable to both gasification and
combustion systems, in the hope that break-through technology can be
identified to reduce the onerous costs and energy penalties of current
approaches.''
OXYGEN COMBUSTION
In a conventional power plant, coal is burned with air to produce
heat and generate steam that is converted to electricity by a turbine-
generator. The flue gas streams are, as a result, diluted with large
quantities of nitrogen from the combustion air. Air contains 78%
nitrogen; only the oxygen in the air is used to convert the fuel to
heat energy. Prior to the last few years, conventional wisdom was that
practicable carbon dioxide separation was not attainable in
conventional coal fired plant designs. Currently, the domestic boiler
suppliers are active in advanced combustion systems research aimed at
carbon management. Combustion of coal with oxygen rather than air is
one of the promising approaches. Oxy-fuel combustion is the approach
that Babcock & Wilcox is most actively pursuing--the approach that we
believe is closest to commercialization.
Progress in B&W's Oxy-Fuel Combustion Program
In the oxygen-fuel fired boiler concept, combustion air is replaced
with relatively pure oxygen. The oxygen is supplied by an on-site air
separation unit, with nitrogen and argon being produced as byproducts
of the oxygen production. For the oxy-fuel boiler system, a portion of
the flue gas is returned back to the burners, and the nitrogen that
would normally be conveyed with the air through conventional air-fuel
firing is essentially replaced by carbon dioxide. This results in the
creation of a flue gas that is primarily a concentrated stream of
carbon dioxide, rather than nitrogen, and other products of coal
combustion. The volume of carbon dioxide-rich flue gas leaving the
plant is about one fourth of that of a conventional air-fired plant.
This concentrated stream of carbon dioxide would then be available for
subsequent sequestration.
Figure 1 schematically compares a modern conventional plant, Figure
1A, to an oxy-fuel power plant, Figure 1B.
In 1999 Babcock & Wilcox joined an international consortium
consisting of utilities, industrial gas companies, and a research &
development organization, to sponsor oxy-fuel combustion in a bench-
scale combustor at CANMET. The bench-scale work showed that
concentration of carbon dioxide is feasible. Some of the developmental
issues could not be addressed at the small bench-scale facility, e.g.,
equipment for introduction of oxygen into the burner, potential need
for boiler heat transfer surface modification, etc. Additionally, we
are conducting a U.S. DOE-sponsored review entitled ``Evaluation of
Oxygen Enriched Combustion Technology for Enhanced CO2 Recovery.''
A larger 5MBTU/HR proof-of-concept pilot-scale evaluation of the
technology is being performed at the Babcock & Wilcox Research Center
in a facility known as the Small Boiler Simulator (SBS) that simulates
full-scale coal-fired boilers. The SBS has recently been modified for
the oxygen-firing of coal with recycled flue gas under a program
sponsored by the State of Illinois. Partial substitution of combustion
air (up to 80%) with oxygen-enriched flue gas has been demonstrated and
plans are in place to replace all of the combustion air with oxygen
this year. A layout of the modified SBS facility appears in Figure 2.
In addition to pilot scale testing, B&W has been working on initial
studies to evaluate the application of oxy-fuel conversion of existing
plants firing different coals as well as the impact on the design of a
new oxy-fuel plant with a high efficiency state-of-the-art steam cycle.
These studies have provided significant insights into the impact of
equipment arrangement options and oxygen and carbon dioxide purity on
both performance and cost; and have provided an opportunity to develop
many of the design tools and establish some of the key parameters
needed to proceed to a full scale demonstration. This study validated
the expectation that nearly all of the major equipment and emissions
control systems in an existing coal-fired plant could be directly
utilized if the plant were converted to oxy-fuel firing. It has also
reinforced the need for an inexpensive source of oxygen to make this
option economical. Considerable opportunity exists for further
refinement of this work toward the goals of optimized performance and
cost.
In portions of our oxy-fuel program, we have worked in
collaboration with an international consortium state agencies
supporting coal usage, USDOE, industrial gas companies providing
oxygen, and utilities.
Future Opportunities, Challenges, and Plans
Preliminary assessment of the impact of oxy-fuel firing on the
design of a new plant with a high efficiency state-of-the-art steam
cycle has revealed potential opportunities for significant cost
reduction. A higher efficiency advanced supercritical steam cycle
reduces the amount of coal burned per megawatt generated which, in
turn, reduces equipment sizes and oxygen required, as well as the
amount of emissions, including carbon dioxide, produced. Current work
has assumed the same amount of flue gas will pass through the boiler as
in conventional units using air instead of oxygen. Reduction of the
amount of flue gas recirculated to the boiler may be advantageous,
further reducing new plant boiler size and associated cost
significantly.
An important secondary benefit of oxy-fuel firing of coal in a
boiler is that, in addition to facilitating carbon management, it also
significantly reduces nitrogen oxide (NOX) emissions. In a
conventional plant using air, NOX is produced from two
sources; a small amount of nitrogen in coal (fuel-NOX) and a
larger amount of nitrogen in from the air used for combustion (thermal
NOX). By using relatively pure oxygen and replacing the
nitrogen with recirculated flue gas, much less NOX is
produced since there is much less nitrogen is available. Furthermore,
some of the NOX in the recycled flue gas will be reduced by
reactions within the flame to molecular nitrogen. This may reduce the
requirements for add-on NOX controls, such as selective
catalytic reduction, to satisfy emission standards.
We plan to continue development of the technology toward full-scale
system design and demonstration. The following areas require further
development work.
Burner Development: A pulverized coal burner capable of introducing
coal and oxygen into the boiler while minimizing the likelihood of an
in-duct coal fire is critical to the successful implementation of the
concept. The mixing of flue gas, coal, and oxygen, especially in the
pulverizer and primary air lines, is an important safety-related design
uncertainty. Other combustion systems such as cyclone firing may offer
additional benefits not only to the fuel handling and combustion system
but also by reducing boiler size. Burners can be developed for safe
oxygen introduction that would reduce NOX, carbon monoxide,
hydrocarbons and unburned combustibles in the fly ash.
Full-scale Demonstration: A full-scale demonstration will be a
critical event in establishment of commercial viability. It will
provide the information and experience needed to allow plant suppliers
to properly design and plant users to gain confidence in the
technology's costs and ability to achieve the desired performance and
reliability. In addition to the ``normal'' operating scenario, a full-
scale demonstration would address such transient events as system
start-up/shut-down and unplanned upsets. To minimize the full-scale
demonstration costs and risks, the first application would likely
involve conversion of an existing coal-fired plant to oxy-fuel firing,
utilizing the existing equipment to the greatest extent possible. Since
only a few new components would need to be purchased and installed, the
most significant being the oxygen supply system, the project cost would
be minimized. Risks also would be significantly reduced because most of
the plant equipment would have already been operated; and, although
some modification would be needed, the controls would be in place and
proven.
New Boiler Applications: One advantage of the oxy-fuel technology
is that it can be retrofitted to the existing units allowing
application to the coal-fired fleet. We anticipate that, based on the
experience of the first (probably retrofit) application, opportunities
will be identified for significant improvements toward optimization of
subsequent retrofits and new plant applications.
Oxygen Production: The cost of oxygen is a major economic hurdle
for both oxy-fuel combustion and gasification technologies. Efforts are
needed to minimize the cost of oxygen to improve economic viability for
these oxygen-based technologies.
Integration with Carbon Sequestration Process: As carbon
sequestration approaches are identified, it will be necessary to
evaluate the suitability of the oxygen-fired boiler flue gas. Even with
good control over boiler air infiltration, and high efficiency
SOX and NOX removal systems, the flue gas will
still contain some N2, SOX, NO, NH3,
etc. The impact of these contaminants will need to be evaluated before
an integrated process can be defined.
Schedule and Cost
Costs for remaining research and development activities are
anticipated to be about $1 million. The full-scale demonstration cost
will be highly affected by site and program specific factors. As a
premature and preliminary estimate, the demonstration might cost about
$15 million.
Mr. Barton. Thank you, Mr. McDonald.
We now want to hear from Mr. David Hawkins, who is the
Director of the Climate Center for the Natural Resources
Defense Council headquartered here in Washington and a frequent
testifier. Welcome to the subcommittee. Your testimony is in
the record. We ask that you summarize it in 5 minutes.
STATEMENT OF DAVID G. HAWKINS
Mr. Hawkins. Thank you, Mr. Chairman.
You should have in front of you some slides to illustrate
the points I would like to make. There are two messages I would
like to convey to the subcommittee today. The first is that we
need to accelerate carbon capture and storage technical systems
if we are going to harmonize the use of coal with protecting
the climate. The second is that the current policy mix is not
going to get the job done on time.
The first point is that U.S. coal plants are aging. The
graphic shows that in 2015, which is just 3 years after the
President's intensity checkpoint, over nearly a third of U.S.
coal capacity will be over 50 years old. And 10 years later,
two-thirds of U.S. coal capacity will be over 50 years old. The
question is, when those units start to retire, what products
are going to be available to replace that power? If we don't
have coal technology that can capture carbon, then the market
is going to choose something else or we will make a commitment
to a high-carbon future that is equally problematic.
On the second slide, this shows the global context, which
is in the next 30 years, there are going to be 1,400 gigawatts
of coal capacity. That is nearly five times the current U.S.
coal capacity that is going to be built. That is a challenge
and an opportunity. It is a challenge because if we build all
of that in a way that can't capture its carbon, we are going to
have a legacy that will be a huge problem for the Twenty-First
Century. If we design it so that it does capture carbon, we are
going to be on our way to being able to solve this problem.
And the U.S. plays a key role. We have the resources. We
have the technology. We have the capability of proving our
technology that can become a global market.
The subsequent slide simply shows that each decade, large
new amounts of capacity are being built. The first decade, the
one we are in, we probably aren't going to be able to affect
the design, but we have got 500 gigawatts coming at us in the
next decade and 700 gigawatts coming at us in the decade after
that. If we get going, we can have a product that will let that
new coal capacity be designed in a way that can protect the
climate.
The next couple of slides illustrate the challenge in a
U.S. context. This is drawn from a national energy technology
laboratory, DOE carbon sequestration road map. I would like to
make just two points about it.
First is that the road map contemplates significant amounts
of actual capture of carbon commencing around 2020. That is 2
years after the President's Clear Skies Act second stage
compliance date. Yet, there is no mention of carbon in that
act, as you know. There seems to be a policy disconnect there.
If we want the industry to be capturing carbon in 2020,
shouldn't we be telling them about that now in order to create
the market signal?
The second point about this example is simply that there is
a large amount of capacity that will need to be deployed. And
it still under this scenario puts the United States in a
position where we will be giving up the option to stabilize
global warming concentrations at what I regard as a prudent
level. That is a major commitment for future generations. And
we should be looking very hard to figure out ways to preserve
options to stabilize at lower levels. We are not going to be
able to return to lower levels once we rush by them.
And then, turning to the last slide on this, the point here
is that policy matters. This illustrates what has happened to
refrigerator energy consumption in the last 50 years. For 25
years, energy consumption of refrigerators went steadily upward
year by year as volumes increased. And then in 1975, it
reversed course. And even though volumes increased and
serviceability increased, energy efficiency went down.
What happened? Policy happened. We adopted reasonable
design standards. We adopted financial incentives. American
industry responded, and it responded in a terrific way so that
today's refrigerator uses about one-third the electricity of
one that you could buy 20 years ago. It has more volume, is
more consumer-friendly.
We can do the same thing with electricity services. We need
to do two things. One is more focus on the existing financial
incentives, both the RD&D and the tax incentives. And, second,
put a policy in place that sends a signal to the private
sector.
And, in conclusion, I would just like to read from the
National Coal Council report of last month. Quoting, ``IGCC may
only become broadly competitive with PC and natural gas
combined cycle plants under a CO2-restricted
scenario. Therefore, vendors currently do not have an adequate
economic incentive to invest R&D dollars in IGCC advancement.
Similarly, power companies are not likely to pay the premium to
install today's IGCC designs in the absence of a clear
regulatory direction on the CO2 issue.'' That is the
coal industry speaking. We agree with that proposition. And we
need policies that will send that signal.
Thank you, Mr. Chairman.
[The prepared statement of David G. Hawkins follows:]
Prepared Statement of David G. Hawkins, Director, NRDC Climate Center,
Natural Resources Defense Council
SUMMARY
Coal's future as an option for the generation of electricity will
be determined in large part by how societies respond to the problem of
global warming, caused predominantly by emissions of carbon dioxide
from the combustion of fossil fuels like coal.
A perception that coal use and climate protection are
irreconcilable activities has contributed to a policy impasse on
confronting the issue of global warming. This impasse will protect
neither the coal industry nor the planet. While energy efficiency and
greater use of renewable resources should remain core components of a
comprehensive strategy to address global warming, development and use
of technologies that capture carbon dioxide and store it permanently in
geologic repositories could enhance our ability avoid a dangerous
build-up of this heat-trapping gas in the atmosphere.
However, because of the long lifetime of carbon dioxide in the
atmosphere and the slow turnover of large energy systems we must act
without delay. Current government policies are inadequate to deliver
economically attractive carbon capture and storage systems in the
timeframe we need them. To accelerate the development of these systems
and to create the market conditions for their use, we need to focus
government funding more sharply on the most promising technologies.
More importantly, we need to adopt reasonable binding measures to limit
global warming emissions so that the private sector has a business
rationale for prioritizing investment in this area.
Further delay in adopting serious efforts to reduce global warming
emissions is a decision to commit the next generation to a large and
effectively irreversible build-up of heat-trapping gases in the
atmosphere. Given what we already know such a decision would not be
responsible.
INTRODUCTION
Mr. Chairman and members of the Subcommittee, thank you for
inviting me here today to testify on behalf of NRDC, the Natural
Resources Defense Council, on the subject of ``Future Options for
Generation of Electricity from Coal.''
Coal is an abundant fuel both in the U.S. and in a number of other
countries. We have used coal to our economic advantage in the U.S.,
fueling our industrial growth from the first years after the War of
Independence and in the past century helping to bring electricity to
nearly every home and hamlet in our country. There is no denying that
our use of the coal that eons of biological and geological processes
bequeathed us has brought great benefits.
There is also no denying that our use of coal has caused great harm
to the health of workers, the general public and the environment. As a
society we have decided to tackle many of the health and environmental
problems caused by coal's use and we are doing a good job addressing a
number of these problems. Indeed, the U.S. leads the world in
addressing many of the problems caused by coal's use. But there is one
problem from coal that we as a society have not yet decided to take on
in a serious manner.
I refer of course to the problem of carbon dioxide emissions
resulting from coal as it is used today. As you know, carbon dioxide or
CO2 is the principal global warming gas. Because
CO2 has a long lifetime in the atmosphere, dramatically
increased use of coal and other fossil fuels since the industrial
revolution has caused a buildup in concentrations of this heat-trapping
gas in the thin layer of life-giving atmosphere that surrounds our
planet.
Our current policy regarding global warming is dysfunctional: it
will not protect the use of coal and it will not protect the planet
from global warming. The coal industry must acknowledge, like it or
not, that the problem of global warming cannot be denied or wished
away. Environmental advocates must acknowledge, like it or not, that
the use of coal cannot be wished away. Denial of these facts is not a
strategy for success for either group's priorities or for society's
interests.
Today I would like to describe why we must not delay in acting to
address the problem of global warming. If we wait longer we will
eliminate the option for our children to avoid risky levels of global
warming gases in the atmosphere--levels that will persist for a century
or more after we have decided to do something to lower them. If we act
now to chart a reasonable program of clear binding limits on global
warming emissions, combined with financial incentives for advanced
technologies for energy sources, including coal, we can avert the worst
of global warming and provide a more plausible basis for the continued
use of coal as a major energy resource.
THE PROBLEM
Despite the chaff that is thrown up when global warming is
discussed as a political matter, the basic science is well understood.
President Bush' Science Advisor, Dr. John Marburger provides an
accurate, though not comprehensive summary of our knowledge:
``Concentrations of greenhouse gases, especially carbon
dioxide, have increased substantially since the beginning of
the industrial revolution. Careful studies show that around
1750 the concentration of carbon dioxide in the atmosphere was
280 parts per million (ppm) and the concentration today is 370
ppm. The National Academy of Sciences indicates, in a report
prepared at the request of the White House, that the increase
of carbon dioxide is due in large part to human activity,
although we cannot rule out that some significant part of these
changes is also a reflection of natural variability. And the
carbon dioxide increases are expected to result in additional
warming of the Earth's surface.'' 1
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\1\ ``The President's Carbon Intensity Reduction Initiative,''
keynote address by Dr. John Marburger Director, Office of Science and
Technology Policy, Executive Office of the President at USDOE
Conference on Carbon Sequestration, Alexandria, Va., May 6, 2003
---------------------------------------------------------------------------
Dr. Marburger describes what we know about what we have done to the
atmosphere already. More problematic is what lies ahead. Growth in
global population and affluence means large and continuing increases in
CO2 from energy use unless we succeed in deploying energy
resources that do not emit CO2. Figure 1, taken from current
forecasts from the U.S. Energy Information Administration and the
International Energy Agency, shows that U.S. CO2 emissions
from energy will grow by 40 per cent in the next 25 years and global
emissions will grow by nearly 70 per cent in the next 30 years.
Absent very large changes in world energy systems, we are on our
way to doubling CO2 concentrations from pre-industrial
levels before a child born today or a coal power plant built today,
retires. A child's retirement may seem like a long way off but given
the inertia in energy systems and persistence of global warming
emissions in the atmosphere, it is not. If we are to have clean energy
resources in place at the required scale and when we need them, we must
set the economic and policy forces in motion now.
Managing global warming emissions is a problem of logistics. We
understand from the history of armed conflict that large amounts of
personnel and materiel cannot be assembled and deployed overnight:
months, sometimes years of mobilized effort are required to place these
resources where we want them when we want them. Supplying clean energy
resources for a growing world is even more challenging.
Figure 2 shows the required ``build-rates'' of clean energy
resources, starting today if we are to keep global temperatures from
increasing by more than 2 degrees Centigrade due to manmade emissions
of global warming gases.
The results, published recently in the magazine Science, are
sobering: globally we should be building between 400 and 1300 megawatts
of zero-carbon-emitting capacity per day between now and 2050 to meet
the world's energy needs in that year and avoid a commitment to warming
unprecedented in the history of modern human civilizations.
2 Yet the forecasted ``clean energy--build rate for the next
30 years is a fraction of that need: only 80 megawatts per day.
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\2\ K. Caldeira et al., ``Climate Sensitivity Uncertainty and the
Need for Energy Without CO2 Emission,'' Science 299, 2052
(2003). To put a 2 degree Centigrade warming in context, recall that
the global average temperature during the last ice age was only 5
degrees cooler than today.
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I hope this fact demonstrates the basic policy irrelevance of the
argument over how rapidly the climate will warm due to manmade
emissions. The Science study shows that even if the climate only warms
at the slowest warming rate in the literature, we are not building
anywhere near enough low-carbon energy resources to avert a change in
the earth's climate that is potentially calamitous.
THE OPPORTUNITY
Secretary of Energy Abraham has said the following about our
options to address this problem:
``Until a few years ago, there were basically only two ways
to address the challenge of global climate change. One was to
produce and use energy more efficiently. The second was to rely
increasingly on low-carbon and carbon-free fuels.
We have made great strides in energy efficiency. We have made
substantial progress in bringing down the costs of renewable
energy, and we are working to reestablish the nuclear power
option. But when you look at most credible projections for
escalating energy use around the globe in the next century--and
you predict the rising levels of carbon emissions likely to
result--you come to an inevitable conclusion: energy efficiency
and alternative energy, alone, may not be enough to stabilize
global concentrations of carbon dioxide. Not unless you assume
that all nations of the world--developed and developing--
undertake a massive overhaul of their energy infrastructures in
a relatively near--and relatively quick--time frame.
I'm not here to offer a detailed assessment of the
practicability of those assumptions, but I'm inclined to think
the odds are strongly against them.'' 3
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\3\ Remarks of Energy Secretary Spencer Abraham to the National
Coal Council on November 21, 2002.
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There is much in Secretary Abraham's statement I would agree with:
energy efficiency and renewable energy resources are the core
components of a successful strategy to keep global warming emissions
from spiraling out of control. We need to do much more to meet our
growing energy requirements by increasing our use of these resources.
But a clear-eyed look at the deployment rates for renewable and
efficiency resources to date raises a serious question whether we will
in fact use them at the scale and in the time frame required to keep
global warming emissions from becoming a runaway problem.
That concern alone causes me to believe it would be wise to rapidly
determine how much we can rely on capture and geologic 4
storage of CO2 from fossil energy resources like coal as a
third tool to cut global warming emissions--a third horse in a troika
if you will. There would be technical and policy benefits from proving
out the approach of CO2 capture and storage (CCS).
Supplementing efficiency and renewable energy with CCS to meet growth
in energy needs has the potential for avoiding the otherwise enormous
forecasted increases in global CO2 emissions. CCS also has
the potential for decoupling the politics of coal from the politics of
global warming. It is understandably difficult for the producers,
shippers and users of coal to acknowledge the reality of global warming
if they believe that doing so is a death sentence for their current
line of business. And leaders of nations like the U.S., China, India,
Russia, Australia, to mention just a few, that have large coal
reserves, have resisted effective measures to curb global warming, in
part due to concerns about the economic and energy implications of
limiting the use of their coal resources.
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\4\ Other concepts, such as biomass storage and ocean disposal,
apart from presenting large ecosystem risks, do not prevent fossil
carbon from being added to the total carbon in the biosphere thus
inevitably increasing atmospheric carbon levels.
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If we want to make CCS available as an option we need policy action
to make it happen. While the components of CCS all have been
demonstrated technically in first or second generation form and are in
limited commercial use, mostly outside the electricity sector, the
private sector today does not have an adequate economic rationale for
making the investments to optimize capture technologies, to prove out
the viability of geologic storage, or to incur the costs of storing
CO2 once captured. I believe a combination of publicly-
funded financial incentives and a schedule of market-based limits on
CO2 emissions is the policy package needed to achieve these
objectives. The current policy approach of an expensive but still
limited research, development and demonstration program will not give
us the results we need in the time we need them.
THE IMPERATIVES OF TIME AND SCALE
For CCS to play a significant role in avoiding carbon emissions in
the next few decades we need to do a lot in a short amount of time,
compared to the usual pace of energy system development. Growth in
global demand for energy, commitments to new coal-fired capacity, and
the aging U.S. coal fleet all place a premium on accelerating our
efforts to deploy commercially viable energy plants amenable to
CO2 capture and to conduct numerous, rigorously monitored
full-scale geologic storage demonstrations.
Consider the issue of new coal plant construction. As figure 3
shows, today's global coal-fired electric generating capacity is about
1000 gigawatts (one gigawatt is 1000 megawatts: the size of one very
large power plant). U.S. coal-fired capacity amounts to just over 300
gigawatts of this total. The International Energy Agency (IEA)
forecasts that between now and 2030 over 1400 gigawatts of new coal
capacity will be constructed.
The IEA forecast is a challenge and an opportunity. If all of this
forecasted capacity is built using conventional technology it would
commit the planet to total carbon emissions approaching 140 billion
metric tonnes over the lifetime of these plants, unless one assumes
that they are backfit with carbon capture equipment at some time during
their life. To put this number in context, it amounts to half the
estimated total cumulative carbon emissions from all fossil fuel use
globally over the past 250 years! If we build any significant fraction
of this new capacity in a manner that does not enable capture of its
CO2 emissions we will be creating a ``carbon shadow'' that
will darken the lives of those who follow us.
Yet a forecast is not destiny. We can avoid this very large carbon
commitment by a combination of efficiency, renewable energy and designs
for new fossil plants that are capable of capturing their
CO2. Because these plants are not built yet, we have more
options than we do with existing plants. Yet, as with all market
opportunities, the market does not wait for the product. If the CCS
product is not proven in time, the market will choose something else.
As figure 4 shows, the rate of new capacity will grow every decade
between now and 2030. We are likely already too late to shape the
design of much of the new capacity being built in this decade. But by
stepping up our efforts now, we can influence the market choice for the
nearly 500 gigawatts of new coal capacity in the next decade and 700
gigawatts of additional capacity in the decade that follows that.
Next consider the issue of aging U.S. coal capacity. It too
represents a market challenge and opportunity. As figure 5 shows, by
2015 (just 3 years after the current administration's carbon intensity
checkpoint), nearly one-third of the current U.S. coal fleet will be
more than 50 years old; about one-tenth will be older than 60 years. In
2025 two-thirds of today's coal capacity will be older than 50 years.
We don't have any experience with running large plants longer than
50 years, so prediction of retirement is difficult. But it is likely
that as these plants age an increasing fraction of this capacity will
be replaced with something new. Both the coal market and our ability to
control global warming depend greatly on the answer. If we do not
develop CCS technologies in time to meet this market demand, we will be
playing a game of technological chicken that either the coal industry
or the planet's climate will lose. On the one hand this capacity could
be replaced by renewable energy or natural gas; an outcome that would
help protect climate but not one that the coal industry would like. On
the other hand the coal industry might succeed in replacing this
capacity with new carbon-emitting coal plants. Though I consider it
unlikely such plants could receive financing, this outcome would
exacerbate global warming.
Finally, consider the scale of deployment of CCS needed to get the
U.S. on a path consistent with stabilizing global warming emissions at
levels less than double pre-industrial levels. DOE's National Energy
Technology Lab (NETL) has published a Sequestration Roadmap that
assesses the contribution that CCS could make to an emissions path that
gradually slows and then stops growth in U.S. global warming emissions.
5
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\5\ NETL, Carbon Sequestration, Tehchnology Roadmap and Program
Plan, March 12, 2003.
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NETL's Roadmap scenario assumes a path for U.S. global warming
emissions that meets the administration's ``carbon intensity
improvement'' goal between now and 2012, then grows at one-half the EIA
reference case forecast until 2020, and then flattens from 2020 to
2050, the end of the NETL scenario period. Figure 6 shows U.S.
CO2 emissions under the NETL Roadmap: in 2020 about 200
million metric tonnes of carbon reductions are needed and by 2050, over
1.6 billion metric tonnes of reductions from reference growth
projections are needed.
To achieve this level of reductions NETL assumes a combination of
enhanced efficiency and renewable energy use, storage of CO2
in forests and soils, and a significant amount of geologic storage of
CO2 captured from industrial gas streams. As figure 7 shows,
under the NETL Roadmap CO2 reductions from CCS amount to
about half of the achieved reductions in 2020 and avoids over 1 billion
metric tonnes of CO2 by 2050 compared to the reference case.
As I will discuss below, to preserve the option of stabilizing
global warming emissions at prudent levels, we will need even more than
this amount of reductions from U.S. reference case forecasts. Yet,
given the policies now in place, it is very questionable that even the
reductions assumed in the NETL Roadmap will occur. Capturing and
storing the amounts of CO2 assumed in the NETL Roadmap will
require building a significant amount of coal-based generating capacity
that is equipped with CCS technology. There are large benefits to be
gained by accelerating the use of CCS as is assumed in the Roadmap but
to cause that to happen, it will be necessary to adopt new policies to
engage the private sector in making the significant investments
required.
Figure 8 shows the amount of coal-based generating capacity that
would need to be equipped with CCS technology after 2020, assuming
those sources provide the bulk of the captured carbon after that date.
In 2020 about 20,000 megawatts (about 60 medium-sized generating units)
of CCS-equipped coal capacity would be needed: a modest amount compared
to what is required in the following decade but large considering that
DOE is proposing a $1 billion effort to build one such plant
(FutureGen) that would come on line toward the end of this decade.
Going from one plant operating around 2008 to perhaps 50 operating in
2020 is likely to happen only if supported with a combination of
government financial support and government policies that provide a
business incentive, by limiting CO2 emissions on a
reasonable but clear schedule.
Even more striking in figure 8 is the amount of coal-based capacity
that would need to use CCS in the years following 2020: 200 gigawatts
by 2030 (two-thirds of today's coal plant total) and over 300 gigawatts
by 2040.
If we are to create this future we need to send the policy signals
now. I submit there is a policy disconnect between the DOE program for
CCS and the administration's proposal for addressing air pollution from
existing power plants.6 As you know, the administration's
Clear Skies Act contemplates compliance schedules extending to 2018 for
these plants. Yet the administration is seeking funding for a DOE
program plan that contemplates significant activity to capture
CO2 from this sector in the same time frame. If we want
coal-based plants to be using CCS systems by phase 2 of the Clear Skies
Act would it not make sense to incorporate carbon management policies
into that Act?
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\6\ I will mention the Clear Skies Act only in passing in this
testimony, with the hope that NRDC will be afforded an opportunity to
present our substantial concerns with this legislation in greater
detail at a future hearing.
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Finally, let me observe that the deployment schedule for CCS
systems would need to be more rapid than assumed under the NETL Roadmap
if planners are to count on it to replace aging U.S. coal capacity. As
shown in figure 5, nearly 90 gigawatts of coal capacity will be more
than 50 years old in 2015, an amount much greater than the assumed 20
gigawatts of CCS penetration by 2020 in the NETL Roadmap.
COMMENTS ON CURRENT POLICY
Current policy to promote development and deployment of CCS systems
consists of federal RD&D funding and proposed federal tax credits. I
would like to make two points about these provisions. First, the
existing and proposed RD&D and tax provisions need more focus on the
most promising technologies to enable CCS in the near term. Second, and
most important, these publicly-funded financial incentives need to be
accompanied by policy measures that will give CO2 a value in
the marketplace in order to assure a timely return on the public's
investment and to create incentives for the required private sector
investments.
Research, Development and Demonstration
The House Energy bill, H.R. 6, contains proposals for significant
expansion of funding for fossil energy RD&D, including a $2 billion 10-
year authorization earmarked for the ``Clean Coal Power Initiative.'' A
major issue in the CCPI is the degree to which Congress should ensure
this sizable funding program is focused on systems that are capable of
capturing CO2. Given the dominant role that coal use plays
in producing global warming emissions and the potential benefits of
perfecting methods to capture carbon from coal-based technologies, I
would argue that the top priority for federal coal RD&D should be early
deployment of carbon capture systems at full commercial scale. But the
current provisions are not structured to achieve this objective.
There is a substantial difference in the readiness of different
coal conversion systems to employ carbon capture technology. As noted
by the National Research Council, gasification technologies produce a
stream of comparatively concentrated CO2 that is amenable to
capture at costs and energy penalties that are substantially less than
currently known methods applicable to conventional coal combustion
technology.
In recognition of this fact, last year's House CCPI provisions
required that 80 per cent of the authorized funding be used for
demonstration of gasification-based systems. In contrast, this year's
bill provides that at least 60 per cent of the funds be used for
gasification approaches. While we should not rule out attention to
carbon capture from combustion-based coal systems, it appears they are
much farther from commercial deployment than are gasification-based
approaches. Accordingly, NRDC urges that more of the $2 billion CCPI
authorization be dedicated to gasification systems.
The tax credit provisions in pending House legislation, such as
H.R. 1213, are even more problematic. Very substantial investment and
production tax credits are authorized for coal-based generation plants.
Yet, the eligibility conditions for these tax credits are structured so
that substantial amounts of the available funds are directed toward
existing coal plants that make only modest improvements in efficiency
and control of conventional pollutants. The problem is that such
investments will not advance the technology needed to harmonize coal
use with global warming concerns. These funds can only be spent once.
Allocating funds to patch up existing units rather than buying down the
costs of carbon capture technologies is akin to buying aspirin to treat
cancer.
Part of the rationale for these tax credit provisions is to keep
older, smaller coal plants running to avoid losses in coal production
currently going to such plants. Yet, if the public policy purpose is to
maintain this production, why not develop a proposal that would repower
such older capacity with systems that demonstrate and buy down the
costs of carbon capture technology? Such an approach would assure that
limited funds are not diverted from the country's top priority needs to
provide a short-term palliative.
Policies to engage the private sector
The central flaw in the current policy suite to promote use of low-
carbon energy resources, including coal with carbon capture and
storage, is the absence of any market-based policy driver
to rationalize private sector investments at the scale required to
produce timely solutions to the problem of global warming. As long as
government policy is confined to public subsidies and exhortations for
voluntary efforts, there is little to no business case to be made for
private sector investments at the requisite scale.
Academic economists have recognized that voluntary approaches are
inherently less effective in driving improvements, affecting the
behavior of only one segment of industry and weakly at that.
7
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\7\ See, eg, Lyon, Voluntary versus Mandatory Approaches To Climate
Change Mitigation, Resources for the Future Issue Brief 03-01, February
2003
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Moreover, the National Coal Council, in its May 2003 report to the
Secretary of Energy on Coal-Related Greenhouse Gas Management Issues
acknowledges the lack of private sector incentives under the current
policy structure:
``IGCC may only become broadly competitive with PC and NGCC
plants under a CO2-restricted scenario. Therefore,
vendors currently do not have an adequate economic incentive to
invest R&D dollars in IGCC advancement. Similarly, power
companies are not likely to pay the premium to install today's
IGCC designs in the absence of clear regulatory direction on
the CO2 issue.'' 8
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\8\ National Coal Council, Coal-Related Greenhouse Gas Management
Issues at 65. May 2003. IGCC means integrated gasification combined
cycle; PC means pulverized coal; NGCC means natural gas combined cycle.
---------------------------------------------------------------------------
It is obvious that some mandatory global warming emissions control
programs can have adverse impacts on the coal industry. It is less
obvious but equally true that the status quo policy is likely to have
adverse impacts on the coal industry by failing to create a business
case for the technologies that are required to permit continued coal
use in a carbon-constrained world. The policy question I hope this
Subcommittee and Congress will address without delay is not whether to
adopt a binding program to limit global warming emissions but what
program to develop. Further delay will not protect the coal industry
and certainly will not protect the planet from global warming.
CONCLUSION
In conclusion let me return to the NETL Roadmap to make a final
point about the cost of delay. While the Roadmap is ambitious in the
current policy context, it is much less ambitious than required to
preserve options to stabilize global warming concentrations at prudent
levels. As shown by figure 9, we will need to do more than stop U.S.
emissions growth in 2020 if we are to retain our ability to stabilize
concentrations at levels less than double pre-industrial
concentrations. 9 Unfortunately, if we cannot do better than
the NETL Roadmap we will forfeit the ability to stabilize
concentrations at 450 and make it close to infeasible to meet a 550 ppm
(double pre-industrial concentrations) level.
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\9\ Figure 9 compares the BAU or reference case emissions to 2050
with the NETL Roadmap and, in the three lower curves the U.S. emissions
consistent with stabilizing concentrations at 650, 550, and 450 ppm
respectively.
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Current debate on global warming assumes that we have ample time to
wait for more evidence about the speed of future warming and then
decide whether and how much to limit emissions. I hope the NETL Roadmap
persuades you of the error in this assumption.
We do not have more time to decide the path we will take. If you
wait, you are making a decision: you are deciding today to commit the
next generation of Americans to a doubling or more of global warming
concentrations, with whatever consequences that entails. By not acting
you will commit us to that path today. I ask you to ask yourselves, are
you confident today that such a future will be benign? If you are not,
then the prudent policy is to take reasonable steps that can preserve
our ability to follow a safer path.
Thank you for the opportunity to testify. I am pleased to answer
any questions you may have.
Mr. Barton. Thank you, Mr. Hawkins. And thank you for
making do. We understand that if we had been in the big room,
you had a PowerPoint that was going to be up where people could
see and having to give a testimony without that technology is a
credit to you. We do appreciate. I did follow along in your
written testimony.
We now want to hear from Dr. Roe-Han Yoon from Virginia
Tech, who has testified for us before. Your testimony is in the
record in its entirety. And we ask that you summarize it in 5
minutes.
STATEMENT OF ROE-HAN YOON
Mr. Yoon. Thank you, Mr. Chairman and members of the
committee.
It is a great honor for me to be here today. I would like
to use the opportunity to address the technological need of the
U.S. coal industry, which has been supplying the most reliable
fuel for power generation.
According to the 2003 annual energy outlook, fuel costs
accounted for 76 percent of the operating expenses at coal-
fired power plants in the year 2000. Therefore, utilities
strive for reducing fuel costs.
The U.S. mining industry did an excellent job in meeting
the demands of their customers; that is, providing low-cost
solid fuels for power generation. In 1979, the price of coal
was $52 per ton in 1996 dollars. In year 2000, it was reduced
to $22 per ton. The 58 percent reduction in price was made
possible because of the nearly 400 percent increase in
productivity.
This remarkable achievement was realized through technology
innovation. It appears, however, to be approaching a limit. In
central Appalachia, the large reserve blocks amenable for
large-scale operations are becoming increasingly difficult to
find.
In 1997, the EIA estimates coal reserves in central
Appalachia to be approximately 17.6 billion tons. In 2003, John
T. Boyd Company of Pittsburgh estimated it to be 7.1 billion
tons, but the coal companies operating in the region reported
only 5.2 billion tons of reserves.
These reserve estimates include the coal that could be
mined in the foreseeable future, perhaps at higher prices. At
today's prices, however, only limited portions of the reserves
are recoverable according to a study conducted by the John T.
Boyd Company. The reasons given by the company included: one,
less favorable geological conditions, such as seam thinning,
which caused operating costs to rise; and, second, difficulty
to offset the rising cost through technology innovation.
Coal companies are also losing a significant amount of coal
during coal-cleaning operations due to the lack of advanced
separation technologies. Of course, loss of coal contributes to
increased cost.
A recent report from the National Research Council
suggested that approximately 70-90 million tons of ultra fine
coal is being discarded annually to 716 impoundments. Since
coal is cleaned in water, the ultra fine coal is being
discarded along with processed water, posing the possibility of
spillage.
In year 2000, a 72-acre coal waste impoundment in Kentucky
accidentally released 250 million gallons of coal sludge to the
environment. To help the U.S. mining industry, we have recently
formed a Center for Advanced Separation Technologies. It is a
seven-university consortium with expertise in coal cleaning,
minerals processing, and environmental control.
I would like to conclude my testimony by showing what
university research can do. We developed under the sponsorship
of DOE a technology known as Microcel, which was designed to
process fine coal. A coal company in southwest Virginia has
been using this technology to recover the ultra fine coal that
had been discarded over the years.
Exhibit 1 in my written testimony shows the pond full of
fine coal sludge. Exhibit 2 shows the same pond after 10 years
of operation. The pond is now almost empty.
More recently, we have developed a novel dewatering
technology, which has been tested on a coal sample from a very
large impoundment in southern West Virginia. As a result of the
successful pilot plant test work conducted as part of an
ongoing DOE-sponsored project, Beard Technology Company in
Pittsburgh is planning to build a 200-ton-per-hour recovery
plant. We are hoping that this plant will be a showcase for
using advanced technologies to transform an environmental
liability into a valuable resource.
Mr. Chairman and members of the committee, I hope that I
have conveyed a message to you that the U.S. coal industry
needs advanced technologies, ocean mining, and separation.
Thank you again for the opportunity to be part of this
distinguished panel.
[The prepared statement of Roe-Han Yoon follows:]
Prepared Statement of Roe-Hoan Yoon, Director, Center for Advanced
Separation Technologies, Virginia Polytechnic Institute and State
University
SUMMARY
Many power companies opted to meet the requirements of the 1990
Clean Air Act Amendment by switching to low-sulfur coals, and Central
Appalachia has been the major source of compliance coals. Recently, the
coal companies operating in this region have been experiencing
difficulties due to high operating costs and low prices of coal. The
price of coal had been declining between 1980 and 2000. During the same
period, the productivity of underground coal mining operations
increased 3.6 times. Thus, the industry combated the difficult market
condition by increasing productivity. However, further increases in
productivity are becoming difficult due to adverse geological
conditions, stringent environmental regulations, and shortages of
trained workforce. It is, therefore, necessary to develop advanced
technologies for increasing mining productivity and improving the
efficiency of separating coal from waste materials. The coal industry
has been producing large amounts of waste at mine sites, creating
public concerns and contributing to increased production costs. These
problems can be minimized by developing advanced mining and processing
technologies. In this testimony, examples are given to show that
advanced technologies developed through research can be used to
transform environmental liabilities, such as fine coal impoundment, to
a valuable resource. Developing advanced mining and processing
technologies will be the key to assuring a steady supply of low-cost
fuels in an environmentally acceptable manner for the U.S. power
industry.
THE COAL INDUSTRY IN CENTRAL APPALACHIA
The 1990 Clean Air Act Amendment called for the reduction of sulfur
dioxide (SO2) emissions in coal-burning power plants. Of the various
options the industry had, the following three were considered most
viable, namely, i) fuel switching, ii) purchasing emission allowances,
and iii) installation of scrubbers. Most of the coal-burning power
plants chose the first two, with about 25% choosing scrubbers. There
are two major sources of low-sulfur coals in the U.S., i.e., western
subbituminous coal and central Appalachian bituminous coal. In 2002,
the coal industry produced 550 million tons of western subbituminous
coal and 248 million tons of bituminous coal from central Appalachia.
In 1997, the Energy Information Administration (EIA) estimated that
central Appalachia has approximately 17.6 billion tons of recoverable
coal reserves, which is defined as the coal that can be recovered
``economically with the application of extraction technology available
currently or in the foreseeable future.'' According to this definition,
the EIA estimate includes coal that can be minable in the future using
more advanced technologies. On the other hand, the John T. Boyd Company
has recently estimated the recoverable reserves in Central Appalachia
to be about 7.1 billion tons (Bate, 2003), while the major coal
companies operating in the region reported 5.2 billion tons of
reserves. Noting that much of the reported coal reserves included the
coal seams that are more difficult to mine, the John T. Boyd Company
``guesstimated'' that only 10-15% of the estimated 7.1 billion tons may
actually be economically recoverable at today's coal prices.
If the price of coal increases in the future, however, the
economically recoverable reserve base in central Appalachia should
increase. On the other hand, coal prices have actually been declining
in real dollars between 1980 and 2000. The U.S. coal companies combated
this problem by increasing productivity. During the same 20-year
period, underground coal mining productivity increased 3.5 times from
1.2 to 4.2 tons per man hour. This remarkable achievement was made
possible through technology development, particularly the longwall
mining method. This technology was introduced to the U.S. coal industry
in 1960s. In 1987, the mining industry made a complete transition from
using medium voltage (1000 V) to high voltage (2400-4160 V) equipment,
which allowed for the development of much larger equipment. This and
other innovations such as self-advancing roof-support systems allowed
companies to mine coal seams at wider face widths and deeper web
cutting depths, resulting in substantial increase in productivity.
However, the large reserve blocks that are conducive to present-day
longwall mining technology are becoming depleted, and companies must
now mine thinner coal seams. Furthermore, they have to deal with
various regulatory hurdles and lack of trained workforce. All of these
factors have contributed to increased costs of producing coal from
central Appalachia. The combination of high production costs and low
coal prices caused financial difficulties for the coal companies
operating in central Appalachia, and a large number of them have filed
bankruptcy proceedings since 2000.
Most of the coal mined in central Appalachia is cleaned of its
impurities such as ash-forming minerals and inorganic sulfur before
combustion. Typically, more than 50% of the run-of-mine (ROM) coal is
separated from waste at coal cleaning (or preparation) plants. In
general, the larger the amount of waste generated, the higher the
operating costs, which are eventually passed on to utility companies.
According to the 2003 Energy Outlook, fuel costs accounted for 76% of
the operating costs for electricity generation in 2000. For this
reason, utility companies are striving to reduce their fuel costs.
Developing advanced mining and coal cleaning technologies would help
coal companies provide low-cost compliance coals to utilities for power
generation.
ADVANCED MINING AND PROCESSING TECHNOLOGIES
The U.S. is the largest mining country of the western world. In
2001, the U.S. produced a total of $58 billion of raw materials, which
consisted of $39 billion from minerals and $19 billion from coal. The
mineral processing industries increased the value of the minerals to
$374 billion, while coal was used to produce 52% of the nation's
electricity and uranium 20%. The dollar value of the electricity
produced from the two mining products was estimated to be $177 billion
in 2001. Thus, the U.S. mining industry contributed a total of $551
billion to the nation's economy, which accounted for 5.4% of its GDP.
According to the 2002 Mineral Commodity Summary, major industries
further increased the value of the processed mineral materials (not
including coal and uranium) to $1.72 trillion, which accounted for 17%
of the GDP.
Despite the large contributions made by the U.S. mining industry,
the research and development expenditure in mining and processing
research is miniscule when compared to that being spent for coal
utilization. The lack of interest in these areas of research stems from
the perception that the technologies used in the mining industry are
mature and there is little room for further improvement. This is far
from the truth. The longwall mining method, for example, was originally
developed in Europe in the 17th century (Lucas and Haycocks, 1973). The
technology continually advanced during the last 20 years, and has been
the main reason that the U.S. coal industry has been able to increase
its productivity. I would hope that development of advanced mining and
processing technologies would become an integral part of the FutureGen
project so that the coal industry can be a steady and reliable supplier
of low-cost fuel for power generation.
It is my understanding that the FutureGen project is to address
environmental issues in coal utilization. It is important to recognize
that environmental problems also exist at mine sites. On October 11,
2000, near Inez, Kentucky, a 72-acre coal waste impoundment
accidentally released 250 million gallons of slurry into nearby
underground mines, creeks, rivers, and schoolyards. This incident
caused Congress to appropriate $2 million for the National Research
Council (NRC) to conduct a paper study to identify causes of the
incident and suggest possible ways of preventing future incidents.
According to the report published as a result of the NRC study, there
are 713 impoundments, mostly in Appalachia, and the coal industry is
still discarding 70-90 million tons of fine coal annually. A recent
study suggested that the fine coal discarded in the various
impoundments in the U.S. may amount to 2.5 billion tons. This is a
significant amount in view of the depleting coal reserves in Central
Appalachia. It is unfortunate that the U.S. mining industry is forced
to discard significant portions of the coal after mining it from deep
underground at high costs.
There are two main reasons for discarding fine coal to
impoundments. First, the separation of coal from ash-forming minerals
is difficult when particle sizes are smaller that approximately 45
microns. Second, the fine coal retains large amounts of water due to
the large surface area, which makes it difficult to handle and
increases shipping costs. Virginia Tech has been developing
technologies that may be used to address these problems. Two years ago,
I had the privilege of testifying in front of this Committee. I talked
about a coal company in Southwest Virginia that was using an advanced
separation technology, known as Microcel, to recover fine coal from an
impoundment. The median particle size of the coal recovered was about
20 microns, which was the reason that it had been discarded in the
first place. Exhibit 1 shows the impoundment when it was filled with
fine coal waste, and Exhibit 2 shows the same pond that is nearly empty
as a result of the remining operation. This is an example of turning an
environmental liability into ``gold'' using an advanced separation
technology.
The pond recovery project in Southwest Virginia was made possible
because the company had an old thermal drier that could be used to
dewater the coal cleaned by the advanced solid-solid separation
technology. Many other companies do not have the luxury of using
thermal driers, which are costly to install and operate. In order to
address this problem, we have also been developing advanced dewatering
technologies, which include dewatering chemicals and a hyperbaric
centrifuge. The former, which is designed to improve the filtration
processes that are currently used in industry, is close to
commercialization, while the latter is being tested at bench-scale. The
dewatering technology has recently been tested on a very fine coal
recovered from a large impoundment in southern West Virginia. The coal
sample taken from the impoundment was cleaned first to 5% ash using the
Microcel technology. The product was then dewatered to 16-18% moisture
using the novel dewatering aids. Based on pilot-scale test work
conducted by Virginia Tech as part of a project sponsored by the U.S.
Department of Energy, Beard Technologies is planning to build a 200-ton
per hour recovery plant.
CONCLUSION
There is a need to develop advanced mining and separation
technologies that can be used to reduce the cost of producing solid
fuels (coal) in an environmentally acceptable manner for the U.S. power
industry. They can also be used to cleanup waste coal impoundments,
thereby minimizing public concerns for the environmental problems
created at mine sites.
References Sited
Lucas, J.R. and Haycocks, C, eds., ``Underground Mining Systems and
Equipment,'' Sec. 12 in SME Mining Engineering Handbook, A.B. Cummins
and I.A. Givens, eds., Society of Mining Engineers, AIME, New York, pp.
485-489, 1973.
Bate, R. L., ``Quantifying the Reserve Dilemma in the Central
Appalachian Mining Region,'' American Coal Council, May 2003.
Mr. Barton. Thank you, Doctor.
Last, but not least, we have Mr. Frank Alix, who is the
Chief Executive Officer of Powerspan Corporation in New Durham,
New Hampshire. I think you, too, had a PowerPoint presentation.
You are going to try to do as good a job as Mr. Hawkins did of
elaborating on it without actually having the visuals. Your
statement is in the record. You are recognized for 5 minutes.
STATEMENT OF FRANK ALIX
Mr. Alix. Thank you, Mr. Chairman. That is a tough act to
follow.
Powerspan is a clean energy technology company
headquartered in New Hampshire. Over the past 5 years, we have
been working to develop a technology called electro-catalytic
oxidation, which is focused on cost-effectively reducing
dioxide, nitrogen oxides, mercury, and fine particulate matter,
principally from existing power plants. Several leading power
generators are investors in the company or partners in
development.
Since we have been pilot testing the technology at a plant
owned by FirstEnergy near Shadyside, Ohio, the first slide
talks about the results we have achieved, consistently
SO2 reductions on the order of 98 percent or better,
NOX reductions of 90, fine particle reduction
PM2.5 greater than 95 percent, and mercury removal
from an Eastern bituminous coal on the order of 80 to 90
percent. Those are good results.
We are moving now to a commercial demonstration of that
technology. The next page will show you what this technology
looks like on a conventional power plant. It shows a boiler, an
electrostatic precipitator.
A conventional scrubber module, the real magic to our
process is what we call the ECO reactor, which is upstream of
the scrubber. And it replaces a selective catalytic reduction
device and a bag house in carbon for mercury. So it really is
one small device that replaces two larger ones in conjunction
with the scrubber. That is why our costs are lower and our
space constraints needed are much smaller.
The next slide down shows what our co-product is of our
process. Obviously the waste from pollution abatement at power
plants is a big issue, whether it is ash or scrubber sludge. We
produce a fertilizer co-product that avoids the need for
disposal of waste.
We actually treat the effluent with activated carbon as
well to remove mercury so that the resulting ammonium sulfate
nitrate fertilizer is below minimum detectable levels of
mercury. This slide shows a pile of actual fertilizer produced
from a coal-fired power plant. And I think the purity that is
evident by the eye is quite striking.
The next slide shows a picture of the commercial
demonstration unit we will be installing also at the Burger
Plant. It is a 50-megawatt unit. We have actually broken ground
in the last month. We expect to have the construction done by
the end of the year.
You can see a little individual standing down there next to
the scrubber, near the stack. So you can see in scale, it is
quite a large unit. It is about a $20 million project. It is a
50-megawatt electric unit. It is a slip stream from a 156-
megawatt boiler.
We want to demonstrate ECO commercial components and
reliability over the course of the next year. And we expect
operation to begin early in 2004.
The next slide will talk about the benefits of ECO. I have
already mentioned the high removal of four major pollutants.
But it is also more readily installed on a space constraints
site. You could see the photograph of the Burger Plant up
against the Ohio River. Typically where pollution control
equipment is installed is on the river side of the plant and
stack.
You can see there is very little room there, even though it
is a small photograph. This is not unusual. A lot of the
existing plants, in fact, have great space constraints in terms
of installing the pollution control equipment we like on them
today.
Also, we think it is going to be adaptable to most
different types of plants and coals. As I mentioned earlier,
the fertilizer co-product is a big benefit. And reducing all of
these emissions in a single installation is also a big benefit.
We have had a cost comparison done by an outside
engineering firm. I refer you to the next slide. It shows that
capital costs are about two-thirds of conventional equipment or
on a 500-megawatt base-loaded plant, we could save on the order
of $50 million.
Fixed O&M, variable O&M, when you add those up, again,
about a one-third savings and two-thirds the cost. So the money
that could be saved on retrofitting existing coal-fired plants
with this technology could be significant.
We have a number of strategic partners that are mentioned
in the following slide, most of them utilities who own coal-
fired generating plants. We have plants in 11 different States
and Ontario, Canada. Also, in the last slide, we show some of
our commercial partners that are well-known in the power,
engineering, and construction field.
So, in summary, I think we have a technology that can have
a big impact on the future of coal generation for electricity.
And our concern is that there is some regulatory policy over
the next several years that develops and gives both the
generating plant owners and technology developers, like
ourselves, long-term certainty so we can obtain the capital in
the time necessary to prove this technology and deploy it.
Thank you, Mr. Chairman.
[The prepared statement of Frank Alix follows:]
Prepared Statement of Frank Alix, Chairman and Chief Executive Officer,
Powerspan Corp.
Chairman Barton and distinguished members of the House Subcommittee
on Energy and Air Quality, thank you for the opportunity to share
Powerspan's perspective on future options for generation of electricity
from coal.
My name is Frank Alix and I am the Chairman and Chief Executive
Officer of Powerspan Corp.
Powerspan is a clean energy technology company headquartered in New
Hampshire. Our company was founded in 1994 and has grown to employ 40
scientists, engineers and other high-tech workers. In order to fund
technology development, the company has raised over $50 million to date
from private, institutional, and corporate investors.
Over the past five years, we have focused our resources on
developing and commercializing a patented multi-pollutant control
technology for coal-fired electric generating plants called Electro-
Catalytic Oxidation, or ECO '. Our ECO technology is
designed to cost-effectively reduce emissions of sulfur dioxide
(SO2), nitrogen oxides (NOX), mercury (Hg), and
fine particles (PM2.5) in a single, compact system. Several
leading power generators are investors in the company or partners in
ECO development. These include FirstEnergy, American Electric Power,
Cinergy, AmerenUE, Allegheny Energy Supply, and Ontario Power
Generation. In 2001 the National Energy Technology Laboratory of the
U.S. Department of Energy awarded Powerspan $2.8 million under a
cooperative agreement to demonstrate the mercury removal capabilities
of ECO under various conditions.
Over the past 16 months, we have successfully pilot tested our ECO
technology in a 2-megawatt slipstream at FirstEnergy's R. E. Burger
Plant near Shadyside, Ohio.
During this testing, ECO technology reduced emissions of:
SO2 by 98%,
NOX by 90% based on typical inlet NOX
conditions,
Mercury by 80-90%,
Other heavy metals by more than 96%,
Total particulate matter by 99.9%, and
Fine particulate matter less than three microns in diameter by
more than 95%.
These pilot test results indicate that ECO is capable of providing
Best Available Control Technology--or BACT--removal levels in a single,
multi-pollutant control system. Furthermore, ECO produces a
commercially valuable fertilizer co-product, avoiding the need for
large, new landfill disposal sites to accept flue gas desulfurization
waste. Finally, a commercial cost estimate for a 500-megawatt (MW)
plant prepared by an outside engineering firm indicates that ECO
capital and operating costs will be two-thirds of the combined costs of
the separate control systems currently required to achieve comparable
reductions in SO2, NOX, and Hg emissions. For a
500 MW plant, this equates to a reduction of about $60 million in
capital cost and $5 million in annual operating and maintenance costs.
I want to emphasize, however, that the technology is still in the
development phase. There could be unforeseen hurdles in moving to
commercialization. Nevertheless, based on the evidence to date, we are
optimistic.
Powerspan has begun installation of a commercial ECO demonstration
unit at FirstEnergy's Burger Plant. The demonstration unit will treat a
50-megawatt slipstream of flue gas, and the plant will burn Ohio coal
with 2-4% sulfur content. The project is being co-funded by Powerspan,
FirstEnergy, and a $4.5 million grant from the Ohio Coal Development
Office within the Ohio Department of Development. Successful completion
of this demonstration in 2004 will allow Powerspan to offer full-scale
commercial ECO systems with standard industry guarantees.
As you consider future options for the generation of electricity
from coal, I would like to focus on the importance of new technology in
preserving the economic viability of the existing fleet of coal-fired
generating plants. Although many had hoped that new natural gas-fired
generation could replace older coal-fired plants, thereby boosting the
efficiency of our electric generating fleet and significantly reducing
air emissions, it is now clear that this strategy poses great risk due
to the limited supplies of natural gas. Likewise, while coal-
gasification technologies promise to reduce emissions and boost the
efficiency of coal-fired generating plants of the future, the existing
fleet of coal-fired plants cannot be economically retrofit with
gasification technologies. Therefore, a significant portion of the
existing fleet of coal-fired plants, that today provides over 50% of
our nation's electricity, need to remain economically viable for at
least the next 20-30 years.
So when considering the future of electricity generation from coal,
it is important to ask what threatens the economic viability of
existing coal-fired generating capacity; where is new technology
needed; and what can Congress do to help? We believe that environmental
regulations, and the uncertainty regarding them, pose the greatest
threat to existing coal-fired plants, and may even inhibit development
of the technology needed to support them.
There is consensus among coal-fired generating plant owners,
employees, investors, regulators and electricity customers that more
should be done to reduce emissions. The environmental and public health
benefits of further reductions in SO2, NOX, and
PM emissions are well documented. The power generating industry, and
the investment community that supports it, have demonstrated their
willingness to invest in new control systems for SO2,
NOX, and PM where the regulations are clear and the cost and
performance of emission control technologies are well known. But while
regulating and controlling SO2, NOX, and PM
emissions has proceeded without threatening the viability of coal-fired
electricity generation, pending regulations for Hg emissions could be
more troubling.
Today, air pollution equipment providers cannot supply Hg control
systems for coal-fired power plants with guaranteed removal rates under
all conditions an operating plant might experience. This is where
technology development is most urgently needed. Although our industry
is optimistic in our ability to provide commercial Hg control systems
at some point in the future, more research and testing is required. The
point at which Hg control technology would be available to support
specific reduction goals for Hg emissions is not yet certain. Still,
environmental technology development is driven by environmental
regulations, and without some clear indication that Hg reductions will
be required, Hg control technology will not be commercialized--leaving
us with the classic chicken and egg dilemma.
So what can Congress do to help?
Both the electric generating industry and the environmental
technology community need long-term certainty in environmental
regulation. For the capital-intensive electric generating industry,
long-term regulatory certainty allows financial markets to provide
sufficient capital for the orderly improvement of generating assets
without threat to the availability of electricity supplies. For the
technology community, regulatory certainty provides the incentive and
time to deploy resources to develop and commercialize new technology
that will meet the regulatory goals in the most cost-effective manner
possible. Therefore, regulations that set achievable emission reduction
goals for SO2, NOX, PM, and Hg over a period of
10-15 years will be most effective at both providing the environmental
and public health benefits we all desire, while maintaining the
economic viability of the existing coal-fired fleet.
You also asked for my thoughts on the proposed FutureGen program
and the Clean Coal Power Initiative. As a clean coal technology
developer, we certainly support federal funding of research and
development activities to enhance the generation of electricity using
coal. However, we believe it is important to examine the extent to
which such federal programs support the near term needs of the existing
coal-fired generating fleet. FutureGen, as it's name implies, is
focused on the next generation of coal-fired plants that may have to
operate in a carbon-constrained environment. As such, this program is
properly focused on coal-gasification and CO2 sequestration
technologies. However, this provides little or no direct benefit for
existing coal-fired plants.
The Clean Coal Power Initiative (CCPI) is more focused on the near
term requirements of coal-fired generating plants. However, 75% of the
$316 million awarded in the first round of the CCPI program was for
projects involving coal-gasification and circulating fluidized bed
projects. These technologies represent less than one-half of one
percent of our present coal-fired generating capacity, and cannot be
economically retrofit to existing coal-fired plants. So even though a
great deal of federal funding has been appropriated to accelerate the
commercial deployment of technologies for coal-fired generation, it is
not clear that the proper balance has been struck between funding the
near term needs of the existing fleet and developing the next
generation of coal-fired plants.
In summary, I believe that it is possible to produce more
electricity from coal and to significantly reduce or even eliminate the
environmental and public health impacts of that production. Our ECO
technology could make an important contribution to that objective. When
evaluating future options for the generation of electricity from coal,
it is important to consider the existing fleet of coal-fired generating
plants and ensure that clean coal technology programs strike a proper
balance between serving the needs of existing plants and providing for
the next generation. Likewise, we should not allow our desire to reduce
air emissions to permit us to issue regulations that threaten the
viability of existing coal-fired plants. These plants are vital to our
economic health and well-being. However, air emissions from coal-fired
plants can and should be significantly reduced from present levels.
Given time and the right regulatory framework, the technology community
will find an economical way to achieve the desired environmental
benefits. History has demonstrated this time and again. And there are
many companies like Powerspan full of talented individuals who are
dedicated to this goal.
Thank you.
Mr. Barton. Thank you, Mr. Alix.
The Chair recognizes himself for the first 5 minutes for
questions.
Mr. Black, your company is operating the pilot program in
Tampa, the gasification project. I asked the DOE witness for
cost comparisons and cost per kilowatt to generate electricity.
Could you elaborate on that a little bit?
Mr. Black. The cost of the plant itself, the capital cost,
was roughly $511 million net of the contribution that we
received from the DOE. To put that cost in context a little
bit, this was a new site that we had to develop. There were a
lot of site development activities, a lot of transmission costs
included. There were a lot of things that are not normally
considered in this kind of exercise.
Mr. Barton. Right.
Mr. Black. But as I stated in my written testimony, when
you just divide the total cost by the megawatts out, it was
about $2,000 a kilowatt.
Mr. Barton. And when we replicate it now that we have kind
of worked the bugs out, what would the cost be compared to a
conventional coal plant?
Mr. Black. We feel that the numbers that Mr. Rudins of the
DOE represented of about $1,600 a kilowatt are reasonable.
Mr. Barton. And how does that compare to a conventional
power plant if you wanted to build one of those today?
Mr. Black. There are some site-specific considerations, but
conventional coal-fired plants are in the order of $1,000 a
kilowatt hour.
Mr. Barton. That's 60 percent more. What about your cost to
generate electricity per kilowatt hour, just your variable
cost? What kind of a number can you give us on that?
Mr. Black. The variable cost, the incremental cost, which
is basically just the cost of the fuel necessary to generate a
kilowatt hour of electricity, is somewhere between 2 and 2.5
cents.
Mr. Barton. Okay. Mr. Rush, you represent a company that
certainly is one of the biggest users of coal outside of the
TVA. How competitive does the gasification of the fluidized bed
technology have to get for your company to look at this to
actually build a new coal plant? Where does the cost breakout
need to come down to?
Mr. Rush. Very similar to what Mr. Black said, we see cost
differences in the 40 to 50 to 60 percent range in capital
costs.
Mr. Barton. How much does that have to narrow before the
environmental benefit offsets the----
Mr. Rush. Generally speaking, we wouldn't agree that there
is a significant environmental benefit for gasification of
pulverized coal.
Mr. Barton. Oh, you would not?
Mr. Rush. We think a new pulverized coal-fired plant can be
built for less money than gasification at efficiencies
comparable to or even greater than gasification and that
emission rate is essentially the same as gasification.
Mr. Barton. Mr. Alix's technology, would that be used on a
pulverized coal plant?
Mr. Rush. That's primarily what it would be used on.
Mr. Barton. So you would, say, use his technology on a
traditional plant, as opposed to the gasification technology
that Mr. Black's company has developed in the pilot program?
Mr. Rush. I wouldn't say use Mr. Alix's technology. There
are many types of technologies to control existing power plants
on the back end. The technology that Powerspan is developing is
just that, still in development. There are commercial plants
that you can buy to give you the same levels of performance
that he is talking about.
I just iterate again we are very much proponents of
gasification going forward. We are trying very hard to find a
way to make----
Mr. Barton. If it was your nickel, you wouldn't order a
gasification plant today. You would order a pulverized coal
plant?
Mr. Rush. Unfortunately, that is the situation we are in.
Mr. Barton. Mr. Hawkins, I recognize that you don't
represent the entire environmental community, but you are the
only one brave enough to come forward and say some semi-
positive things about coal, which we give you great credit for
doing that. I don't want to put words in your mouth, but I am
going to kind of do that.
Would it be safe to say that the environmental community
generally would oppose any new coal plants being built but they
might accept a coal plant that used this gasification
technology or something that had the capability to capture and
sequester carbon, carbon dioxide?
Mr. Hawkins. I will speak about NRDC's position, which is
that NRDC would oppose a new conventional plant being built if
it were not equipped with technologies capable of capturing
carbon.
And we would work with project developers. We are not going
to impose our will on a particular local community, but we
would work with project developers of technologies using coal
that are capable of capturing carbon. We think that is the way
to harmonize these 2 objectives.
Mr. Barton. And does your organization have a view on the
technology of the pulverized coal plants versus the
gasification plants?
Mr. Hawkins. Well, Mr. Chairman, I am a lawyer, not an
engineer. So I can only go by what I read.
Mr. Barton. Well, I am an engineer, not a lawyer. I can
only go by what you tell me since it is your testimony.
Mr. Hawkins. This is a dangerous situation.
One of the things that most of the reviews have been done
indicate that gasification is much closer to being able to
capture carbon in an economical fashion than other systems.
There are pilot and bench-scale activities for combustion-based
systems, but they are I would say at a minimum several years,
perhaps a decade behind where we are with respect to
gasification.
So if you are talking about building new coal plants in the
next decade and you want to preserve your ability to capture
carbon, I think that gasification is the technology of choice
at the moment. If combustion systems catch up, that will be a
development to be applauded.
Mr. Barton. Okay. Mr. Alix, my time has expired, but I want
to give you the last word on this if you care to take it.
Mr. Alix. I would agree with both testimonies earlier that
systems available for pulverized coal today are much more
economical. And there are other technologies to rule emissions
besides ours. Ours perhaps will be the most cost-effective ones
commercially available.
I think as well their removing CO2 from a highly
concentrated stream, as represented by coal gasification, is an
easy task. There are technologies, however, that can be
deployed, at least in the developmental stage, to remove
CO2 from a PC boiler. And one of the companies we're
working with, Fluor Daniel, is looking to test some of that in
Canada.
So there are technologies moving along that front. How far
they are from commercialization, whether that's 5, 10, 15 years
away, I can't comment.
Mr. Barton. My time has expired. The gentleman from
Virginia.
Mr. Boucher. Thank you, very much, Mr. Chairman. I want to
thank all of the witnesses for taking the time to inform the
committee today with your very carefully prepared testimony.
Mr. Rush, let me begin with you and ask if you have had an
opportunity to look at the tax credits that are provided in the
Senate version of our comprehensive energy bill that are
directed toward encouraging electric utilities to acquire and
deploy a new generation of clean coal technologies.
The bill contains investment tax credits. It contains
production tax credits. These credits are along the lines of
the measures that have been recommended in the House by Mr.
Whitfield, who until just a moment was here; Mr. Strickland;
Mr. Doyle; and myself.
Our goal is to, first of all, encourage the development and
the use of the clean coal technologies, but, even more broadly,
the goal is to encourage electric utilities to use coal,
instead of natural gas in a large number of the new
electricity-generating plants that will be built over the next
25 years.
With that background, would you care to comment on how well
these tax credits might achieve those goals? Should they be
enacted and make their way into the final energy bill?
Mr. Rush. Well, since I was familiar with the tax credits
from 2 or 3 years ago, before they came into their final form,
and I have not looked at the current form in any great detail,
my general understanding is that the form that they were
offered in 2 or 3 years ago was more aggressive in terms of the
tax credits than are in either the House or Senate bills.
I think that the more aggressive proposals of 2 or 3 years
ago would go a lot further toward incenting new technology than
those that are on the table today. But those that are on the
table today are better than nothing.
Mr. Boucher. Would we achieve the goal of encouraging your
company, for example, to use coal, instead of natural gas, in
new plants?
Mr. Rush. I think the fair answer is I have not analyzed
the new numbers. I have only observed that the percentages have
come down. And it would have been a push at the higher numbers
2 or 3 years ago.
Mr. Boucher. Okay. Well, thanks for your honesty. I am
hopeful that we will come out with final numbers that will
achieve the goal. If you would care to take a look at those tax
credits and tell us whether you think they will achieve their
goal, at least in terms of the way your company would respond,
I think that would be extremely helpful.
Mr. Ferguson, I know that when you built your coal gasifier
about 20 years ago and it has been in commercial operation
since, it was constructed without government assistance. This
was done entirely with private sector dollars.
Your goal in building this gasifier was, in part, I guess,
to generate electricity for your internal use and also to
derive chemicals from the process that can be utilized in your
chemical operations. And it has been a success, as I understand
it. Is that correct?
Mr. Ferguson. That is correct.
Mr. Boucher. And it is a commercial success for you today.
I know that you also support a government role in
developing clean coal technologies and that you would support a
government role in developing coal gasification technologies.
Why do we need that government role, given the fact that you
have an example of a commercially successful technology that
hasn't required government funding?
Mr. Ferguson. Good question. The primary purpose that we
built our gasifiers for was to provide raw materials for making
chemicals, primarily chemicals for Eastman Kodak at that time
that are used in photographic purposes. That is, frankly, one
of the reasons why we had to have all the mercury removal
capabilities over those years.
It was very economically attractive for the purposes of
generating raw materials compared to other sources of
electrical generation. It has just recently emerged with the
ever-rising costs of natural gas and the dislocation of costs
between natural gas and coal.
I guess maybe the primary reason, though, I think we need
the incentives is that it befuddles us that people refer to
this as a new technology. It's another day at the office for
us. I think for most of the power-generating community, this is
a new technology; therefore, it has perceived risk.
We have operating factors that are not demonstrated
anywhere else in the industry. And without faith in those kinds
of operating factors, there is a perceived risk that has to be
overcome before the gentlemen on my left are willing to invest
in gasification.
So we believe that it needs a little kick-start through
that process to reweight the risk-reward proposition for the
early days. At the end of the day, if we can demonstrate the
kind of operating factors that we have had in our company, we
are quite certain that it will be able to stand on its own and
be very successful, as we have been since starting 20 years
ago.
Mr. Boucher. Well, thank you. And congratulations on the
success of a technology that I believe the sole example of a
stand-alone commercial gasifier in the U.S. really is your
facility in Kingsport, Tennessee. Congratulations on that
success.
Dr. Yoon, in the brief amount of time I have remaining,
which is none, I would like to just ask one question of you.
Please be as brief in your answer as I am in asking the
question.
Your technology enables the recovery of fine coal particles
that in the absence of your technology would be discarded as
waste. Can you talk just a little bit about how that technology
contributes to the overall competitive position of coal and why
would an electric utility or a coal company have an interest in
using the technology that you have developed that achieves that
result?
Mr. Yoon. Whatever coal you lose after mining will be a big
factor in determining the final price of the coal. So
recovering fine coal or not losing any coal you have mined,
spending your own investment money, is very important in
reducing the price of coal for power generation.
Mr. Boucher. Thank you very much.
Mr. Chairman, my time has expired. I thank you for your
indulgence.
Mr. Whitfield. Yes, sir. Thank you.
First of all, I would like to ask unanimous consent to
enter into the record the National Coal Council report that I
believe Mr. Hawkins referred to. If there is no objection, I
would like to enter that into the permanent record.
[The National Coal Council report is available at: http://
www.
nationalcoalcouncil.org/Documents/May20001report-revised.pdf]
Mr. Whitfield. Mr. Olliver, in your testimony, you I
believe said that your plant was the cleanest coal-using plant
in the world. Is that correct?
Mr. Olliver. Yes, it is.
Mr. Whitfield. Is there unanimous agreement in that? There
is no question about that, I take it? Is that correct?
Mr. Olliver. I would hope so. It's a matter of public
record by the Department of Energy analyzing the performance of
all of the clean coal projects that have been built and
operating.
Mr. Whitfield. How much did it cost per kilowatt hour to
build that plant?
Mr. Olliver. Well, as was mentioned by my friend from Tampa
Electric, the actual costs, capital costs, of those projects
were higher than would be expected. I think roughly between
$1,500 and $2,000 a kilowatt installed would be valid for our
plant. The current plants that are envisioned for new
technology, new operating plants, again it is estimated between
$1,200 and $1,400 per kilowatt.
Mr. Whitfield. Is your company currently planning to build
or operate any new gasification plants?
Mr. Olliver. Yes. We have 2 projects that are in project
development in the United States. One is the Kentucky pioneer
project in Trapp, Kentucky and another project in Lima, Ohio,
which will incorporate our E-GAS technology for the
gasification of coal.
Mr. Whitfield. You said in Trapp, Kentucky?
Mr. Olliver. That is correct.
Mr. Whitfield. I am delighted to hear that.
Mr. Hawkins, I am not sure you said you were speaking for
your organization or not, but you all really do not have any
problem with these gasification plants. Do you feel comfortable
with those? Is that correct?
Mr. Hawkins. Well, I am speaking for my organization,
Congressman Whitfield. And I would say that we favor clean
energy resources. We can do a lot more with renewable energy
than we are currently doing. I think we can do a lot more with
energy efficiency than what we're currently doing.
With respect to fossil fuel facilities, we recognize that
coal is an abundant resource. And if there are going to be
additional capital commitments to new coal projects, we think
they should be ones that are designed to capture carbon. And
gasification appears to be able to do that.
Mr. Whitfield. And Mr. Rush had indicated that pulverized
coal is something that his company is certainly using. And if
you were going to be building in the future, you would feel
quite comfortable in continuing to build those plants. Is that
correct, Mr. Rush?
Mr. Rush. Yes, that is correct. I think there is sort of an
issue of semantics here. All fossil-fired power technology is
capable of CO2 capture. The issue is not
technically, can you do it? The issue is, can you afford to do
it?
Mr. Whitfield. Right.
Mr. Rush. With the current technology, if you project
CO2 capture and sequestration onto the technologies
we have today, you get about a 40 percent increase. With
gasification, you get about a 60 to 80 percent increase with
pulverized coal.
But, as David has heard me argue a number of times, the
world's scientists have only within the last 5 or so years
really turned to CO2 capture. We're using technology
that was developed by the petroleum industry for use on a very
high value end product. Electricity is a commodity product. In
the next 10 years, I am quite confident, given my 30 years in
R&D that the probability of developing cost-effective
CO2 capture technology for atmospheric combustion
systems is quite high.
Mr. Whitfield. Periodically you will read various
scientists, this fellow who wrote the book, skeptical
environmentalists, and others. And they talk about
CO2 emissions that are primarily natural occurring
versus manmade CO2 emissions. Some people make the
argument that the manmade emissions are simply not that serious
of an issue compared to that made by nature.
I was wondering if any of you had any comment on that. Mr.
Hawkins?
Mr. Hawkins. Yes. If you look at the amount of carbon on
the planet, before we started burning fossil fuels, there were
about 600 billion tons of carbon in the atmosphere. The
estimated fossil reserves are 5 trillion tons. If we take those
5 trillion tons out of an isolated fossil reservoir and put
them into the atmosphere, there is going to be a change. That
is not a trivial contribution. We are talking about a factor of
10 additional carbon.
Not all of it will stay in the atmosphere. Some of it will
cycle into the ocean over time. But basically the carbon you
put up into the air today, if you put 100 tons in the air
today, 40 tons are there 100 years from now. And 15 tons are
there 1,000 years from now. So if we don't change the rate of
fossil fuel consumption and release of the fossil carbon to the
atmosphere, we will have a phenomenal impact. And all analyses
indicate that it will be a phenomenally negative impact.
Mr. Whitfield. Anyone would like to make a comment to that?
[No response.]
Mr. Whitfield. Okay. I am going to ask one other question,
then Mr. Strickland. Certainly China and some other what we
might call developing countries are using more and more coal.
And so many of these international environmental agreements
that we have give them a lot more leeway than we do our own
companies. From the position of the NRDC, how would you all
approach that? What can we do to ensure that some of these
countries are using more and more clean coal technology?
Mr. Hawkins. Thank you for asking that question. I tried to
address it briefly in my testimony. Basically we need a
strategy to engage with the developing countries, as my
testimony points out. Huge amounts of new coal capacity will be
going into China and India.
The Department of State and the Department of Energy today
are hosting a conference across the river--I spoke at it
yesterday--getting together the major coal-consuming and using
countries of the earth.
I think what we need as a strategy is something that says
there is technology that allows you to use your resource and
allows you to protect the climate as well. Carbon capture and
storage is such a technology. I think that if we take the
leadership, we can essentially make a strategic investment.
We can show that developing countries do not have to choose
between taking a path that will be dangerous to the planet's
climate or a path that is conducive to their economic
development. And this kind of technology is a strategic
opportunity.
It also has the advantage of putting us in a position to
capture the global marketplace because a carbon-constrained
world is coming. If we get out there with the technologies, we
will have a market. And we should take advantage of that apart
from the advantage of engaging these developing countries.
Mr. Whitfield. Do any of the other panel members have any
comments on that relating to the transferability of this
technology and so forth? Mr. Ferguson?
Mr. Ferguson. Because of our long history in gasification
and the interest of the Chinese in using gasification as a
source of raw material to make chemicals, particularly
fertilizers, we have been approached often by the Chinese in
their interest in the concept of polygeneration, plants that
would manufacture fuel, manufacture town gas to substitute for
natural gas, which they could distribute in pipelines, material
that would make fertilizer for their chemical purposes.
I am in agreement with Mr. Hawkins on his point that this
will be a big deal in the Asian economy, especially the Chinese
economy. And someone will fill that void for them. We have been
approached very, very often about our ability to help them on
those projects.
Mr. Whitfield. Anyone else?
[No response.]
Mr. Whitfield. Okay. Mr. Strickland?
Mr. Strickland. Thank you, Mr. Chairman.
Mr. Alix, I represent Shadyside, Ohio, and I drive by the
plant frequently. I did over the last weekend. The question I
have is, when do you expect this electro-catalytic oxidation
technology to be commercially available? Do you have an
estimate?
Mr. Alix. Well, our first commercial unit will begin
operating first quarter 2004. That is always a bit of a risky
endeavor. We, of course, as technology developers, tend to be
quite optimistic and expect that it will come up and run well
and people will line up to order that within a few months.
What typically happens is it comes up and you identify
areas where you can improve the performance and reliability,
may go through a few months of changes, and then you begin the
long cycles of running, where one developer who has got a
particularly acute problem may say 6 to 12 months after seeing
this run reliably and produce results, ``I would be willing to
give you an order.'' Now, that order might take 2 to 3 years to
generate a commercial unit. So commercially available, probably
2007 is the right timeframe when you could actually see it
operating on a commercial plant.
Mr. Strickland. Do you expect this technology to work
equally well with older plants that may be retrofitted with the
technology as well as a new plant that is built with it? Do you
have any reason to believe that there is likely to be less of a
positive benefit using an older plant?
Mr. Alix. No. We see the technology really has been
operating. As you know, Shadyside, the Burger Plant is a mid-
1950's vintage. Certainly we have targeted the older plants
that need retrofit, but I think it could work equally well on
either.
Mr. Strickland. I have a question that is sort of a general
question for the panel. We are aware that the EPA is moving to
propose new standards for mercury emissions this December, to
promulgate those rules by December of 2004, with compliance for
existing facilities to take place in December of 2007.
I raise this issue because coal-fired electric power
plants, according to EPA data, account for approximately one-
third of the total U.S. mercury emissions.
So I really have three questions. What technologies are
available to the industry today to begin to prepare for the
mercury MAACT rule? In your opinion, will industry invest in
these technologies at projected costs or will coal plants
likely shut down under a mercury MAACT rule absent a clean air
bill this Congress or next? And, third, if plants may cease to
operate under new mercury regulations, what should Congress do
to ensure that we do not lose an affordable source of
electricity? Would any one or more of you like to respond to
that?
Mr. Hawkins. I would like to, Congressman Strickland. The
requirement of the Clean Air Act is a technology-based
requirement. So EPA is not in a position to adopt rules that
are technically or economically unfeasible. That means that the
prospect of power plants, coal-fired power plants, shutting
down because of the mercury rule is quite slim, if not
nonexistent.
Congressman Waxman read from a recent report published in
the coal industry trade association magazine indicating that
technologies have, in fact, been demonstrated that can achieve
on the order of 90 percent mercury control from different types
of coal, Eastern and Western, and do so with minimal capital
costs and minimal operating costs.
The response to that from some of the industry witnesses
was, well, that hasn't been done on a widespread basis. Well,
that's not a surprise. It hasn't been required. And companies
are not in the business of volunteering to control pollutants
that they haven't been asked to control. That's just an
unfortunate fact of life.
With these standards adopted, I think we will see the
deployment of that technology. And that will provide a
tremendous benefit because we are talking about something that
is a brain toxin that accumulates in the environment. And the
faster we get about cutting back on major controllable sources
in this country, the greater improvement we will see. We will
also see that technology deployed worldwide, which will also be
an enormous benefit because some of the mercury that falls in
the United States comes from coal plants in other countries.
If we do it, we will get the rest of the world to do it,
just as we did when we took lead out of gasoline. We did it,
and the rest of the world followed. We've got a great
opportunity here.
Mr. Strickland. If I could just say a word before I ask if
anyone would like to respond? You seem very sure that if we do
it, the rest of the world will follow. I would be interested in
knowing how you can be so sure that will happen.
You act as if you would like to respond. So I will give you
a chance to respond, sir.
Mr. Hawkins. Thank you. I would point to two examples. We
cleaned up automobiles in this country, and the rest of the
world has followed. We took lead out of gasoline in this
country, and the rest of the world is following.
When we show that the technology is there, people around
the world have an aspiration for a healthier environment. The
only reason they're not pursuing it is because the technologies
don't seem to be available.
We can lead in this respect. We have done it in the past,
and we have got real-world examples where the world has
followed.
Mr. Strickland. I don't want to be argumentative because
you very well may be right. You know more about I guess the
history of this than I do. But you just said that in this
country, industry is not going to do it unless they are forced
to. And it seems that you've said that other countries will do
it simply because it is the right thing to do. And that seems
like it's a contradictory judgment to me.
Mr. Hawkins. The other countries adopt policies when those
policies appear to be economically and technically feasible.
What we have done in this country using the resources we have
and the ingenuity we have is to show the rest of the world
those policies are economically and technically feasible. And
then they adopt those policies. And then the industries comply
with those policies.
Mr. Strickland. Mr. Chairman, could I ask for an additional
minute to give anyone else on the panel to respond if they
would like to because I think I saw indications that some would
like to respond?
Mr. Rush. Yes. It's unfortunate there have been a number of
questions about mercury here today. Southern Company's expert
on mercury testified before a congressional committee within
the last 2 or 3 weeks, Dr. Larry Monroe. Would it be
appropriate to enter his testimony in the directorate of this
committee?
Mr. Whitfield. Without objection, yes, sir.
[The prepared statement of Larry S. Monroe follows:]
Prepared Statement of Larry S. Monroe, Program Manager of Pollution
Control Research, Southern Company, Before the Senate Environment and
Public Works Committee, Subcommittee on Clean Air, Climate Change and
Nuclear Safety, June 5, 2003
My name is Larry S. Monroe and I am the Program Manager of
Pollution Control Research for Southern Company. Southern Company is a
super regional energy company serving customers in Alabama, Florida,
Georgia, and Mississippi. Southern Company is the second largest user
of coal in the utility industry with some 21,626 megawatts of coal-
fired generating capacity. I hold a Ph.D. in Chemical Engineering from
MIT, and have been involved in research on pollution control for coal-
based power plants for over 20 years in university, not-for-profit
research institute, and corporate settings. At Southern Company, I
manage a research group that evaluates, develops, demonstrates, and
troubleshoots technologies to control particulates, SO2,
NOX, and hazardous air pollutants, including mercury, from
fossil-fired power plants.
For the last 2 years, I have been engaged in the national effort to
develop technologies to control mercury emissions from coal-fired power
plants, resulting from EPA's decision in December 2000 to develop
Maximum Available Control Technology (MACT) mercury regulations for
coal plants. I serve as the utility co-chairperson of the EPRI program
tasked with developing and evaluating mercury control technologies. I
have also directed Southern Company's efforts, along with our partners
including other utilities, EPRI, the Department of Energy, and the
Environmental Protection Agency, in an attempt to develop cost-
effective controls of utility mercury emissions.
I have been representing Southern Company and the industry on the
Utility MACT Working Group, a subcommittee formed under the Clean Air
Act Advisory Committee to provide advice to the Environmental
Protection Agency. As a member of the MACT Working group, I have been
intimately involved in the discussions with all of the stakeholders--
including the environmental community, the state/local/tribal
regulatory agencies, and the industry stakeholders--on the form of the
regulation and its impacts on the industry and the price of
electricity. As a part of this effort, I have been the leader of the
industry stakeholders on advising EPA on our view of the performance
and cost of the available mercury control technologies.
Working with EPRI, DOE, and EPA, Southern Company is one of the
leading utilities in the national effort to develop mercury controls.
We hosted the first full-scale power plant testing of mercury control
ever performed in the United States, and are just starting a long-term
follow-on test at the same site. Southern has also established a unique
program to explore the fundamentals of mercury chemistry in coal power
plant flue gas, partnering with EPA, TVA, EPRI, and several other
utilities.
Today I am also testifying on behalf of the Edison Electric
Institute (EEI). EEI is the association of U.S. shareholder-owned
electric companies, international affiliates and industry associates
worldwide. EEI's U.S. members serve more than 90 percent of all
customers served by the shareholder-owned segment of the industry,
generate approximately three-quarters of all of the electricity
generated by electric companies in the country, and serve about 70
percent of all ultimate customers in the nation.
State of Technology
The state of technology development for control of mercury
emissions from coal-fired power plants is very much in its infancy.
Some early efforts at measuring the mercury emissions from power plants
were attempted in the mid-1990's, but the sampling techniques used were
not adequate, and much of that data is questionable. The mercury
content in typical coal-fired power plant flue gas is very low,
measured at the parts per trillion level. A good analogy that describes
the low concentration of mercury in coal-fired power plant flue gas is
to imagine a pipe, one foot in diameter, built from the earth to the
moon. If this pipe, all 238,000 miles long, were to be filled with
coal-fired power plant flue gas, and the mercury all magically brought
to one end, it would only take up the first 18 inches of this pipe. If
we compare the mercury in coal-fired power plant flue gas to the other
criteria pollutants (e.g., particulates, NOX, and
SO2) you find that the mercury is one million times less
concentrated than those other species. The low concentrations of
mercury, along with the propensity of mercury to react in the sampling
equipment, contribute to the difficulties in accurately measuring and
controlling mercury emissions at cost effective levels.
The state of knowledge of mercury chemistry and mercury emissions
from power plants has been so scarce that, in 1999, the Environmental
Protection Agency (EPA) required all power plants to sample their coal
supply and test for mercury content, and required a selected number of
power plants to sample for the different mercury species before and
after the flue gas entered existing pollution control devices. Southern
Company participated in that effort by tracking every coal to every one
of our power plants and further by sampling two of our plants for
mercury species and emissions. Unfortunately, this EPA Information
Collection Request (ICR) database, while suffering from some flaws in
data collection and power plant selection, remains the best publicly
available database of mercury emissions, with and without controls, and
of mercury chemistry for U.S. power plants.
There are currently no commercial technologies that are available
for controlling mercury from coal-fired power plants. That is, there
are no vendors that are offering process systems that are supported by
guarantees from the vendor for mercury control performance under all
the conditions that an ordinary power plant is expected to encounter
over the course of normal operating conditions and timelines. Of
course, there are vendors that will offer their best guess at how a
particular technology will perform, but the risk of non-performance
rests with the utility. The reliance on vendor warranties is standard
practice within the utility industry, and the inability of the vendors
to issue guarantees is indicative of the pre-commercial status of all
mercury control technologies.
The most promising two technologies for mercury control in power
plants are co-control by flue gas desulphurization (FGD) processes and
the use of activated carbon injection (ACI) processes. To understand
the co-control of mercury by FGD processes and the possibility of
increased mercury control by NOX control processes, namely
selective catalytic reduction (SCR) systems, a basic understanding of
mercury chemistry is needed. First, coal is no different than any other
solid material dug from the earth's crust when it comes to the mercury
content. In other words, coal is not enriched in mercury compared to
ordinary rocks. The mercury in coal is there mainly as a sulfide
compound, at a concentration that averages 50 parts per billion by
weight. These sulfur-mercury compounds are the most common form of
mercury found in nature and they tend to be very stable solids, only
dissolved by a mixture of strong acids. Most everyone is familiar with
mercury, the metal that is a liquid at room temperature and used widely
in thermometers and blood pressure instruments seen in a physician's
office.
It is not a surprise that a metal that is liquid at room
temperature would boil at much lower temperatures than ordinary metals,
and mercury boils at only 674 deg.F. Similarly, when coal burns in a
utility boiler, mercury in the coal vaporizes and produces the vapor of
the metal in the high temperature zones of the flame. This form of
mercury is commonly referred to as elemental mercury, meaning that it
exists in a form that is not combined with any other element. It is
also known as ``mercury zero,'' a reference to the chemist's shorthand
of referring to the electron state of a pure element as zero, or Hg\0\.
As the temperature of the coal flue gas is cooled by the process of
making and superheating steam, the elemental mercury vapor can react
with other elements to form compounds. Our best knowledge of mercury
chemistry suggests that mercury vapor can react with either chlorine or
oxygen to produce mercury chloride (HgCl2) or mercury oxide
(HgO). Since the electronic state of the mercury atom is now ``plus
two,'' this form is sometimes called ``mercury two,'' ionic mercury, or
oxidized mercury. These are all equivalent terms that describe the
chemical state of the mercury. Finally, either of these two forms of
mercury, the elemental or the ionic, can attach to solid particles,
either fly ash or partially burned coal particles, and is typically
referred to as ``particulate mercury,'' which is a physical description
of the mercury form. To summarize, we generally classify the mercury in
coal flue gas as being one of three forms: elemental, ionic, or
particulate.
The proportions of the three chemical forms of mercury have a great
influence over the behavior of the mercury in the flue gas in pollution
control processes. The particulate form of mercury is the easiest form
to remove, with high efficiency capture being normal along with the
coal ash in electrostatic precipitators (ESPs) or bag houses.
Unfortunately, in most power plants, the fraction of mercury contained
in the particulate form is only a minor amount of the total mercury.
Flue Gas Desulphurization (FGD)
The most common method to remove sulfur dioxide (SO2)
from coal-fired power plant flue gas is a wet scrubber. This device is
a large tower, where the flue gas enters the tower near the bottom and
flows upward, exiting through the top. When the flue gas is flowing,
hundreds of nozzles spray a mixture of powdered limestone and water.
The flue gas essentially flows up through a rain storm of these
limestone-water droplets. Since SO2 is an acid, it reacts
with the alkaline limestone solids and is neutralized.
The acid and base chemistry is so fast that the performance of the
wet scrubber is dependent on the mixing between the flue gas and the
droplets. Therefore, it is necessary to use multiple, large pumps and a
large number of nozzles to produce the small droplets needed. The
combined limestone-SO2 product from the scrubber is
typically calcium sulfate, better known as gypsum--the white powder
found inside wallboard (also called sheetrock). Gypsum is a naturally-
occurring compound, mined both for fertilizer and wallboard.
In this common FGD process, the wet limestone scrubber, the form of
the mercury in the flue gas entering the scrubber appears to be the
most important factor in the efficiency of mercury capture. The ionic
form of mercury, that which has reacted with oxygen or chlorine, tends
to be soluble in water and is therefore captured along with the
SO2, while the elemental mercury, being insoluble in water,
passes through most of these processes. Therefore, our best
understanding of the co-control of mercury with SO2 control
processes suggests that the efficiency of mercury capture by these
processes is related to the amount of the mercury that has converted
from the elemental form to the ionic form. Anything that would help
convert the elemental mercury to the ionic form will presumably
increase the overall mercury control in plants equipped with wet
scrubbers. (NOX control processes using selective catalytic
reduction systems appear under some circumstances, and with some coals,
to increase the amount of ionic mercury, and this will be discussed
later.)
The biggest influence on the eventual form of mercury in the flue
gas, and the apparent subsequent capture efficiency, appears to be the
chlorine content of the coal. Coals with higher chlorine levels, when
burned in a power plant, produce flue gas that is typically higher in
the ionic form, the form which is most easily captured in an
SO2 scrubber system. In general, the domestic coals found
east of the Mississippi River tend to be much higher in chlorine
content than the coals found in the West.
More specifically, the rank of the coal tends to be a good
predictor of chlorine content. Coal rank is an indicator of the age of
the coal and there are four major classifications of coal rank, listed
in the order of high rank (or older coal) to low rank (or younger
coal): anthracite, bituminous, sub bituminous, and lignite. Most coal
found in the Eastern U.S. is bituminous coal, although there are some
lignite deposits found in the Alabama-Mississippi coastal plain. These
lignite reserves are not important to the coal-fired utility industry,
however. Conversely, most of the coal found in the Western U.S.,
including Texas, is either sub bituminous or lignite rank coal. The
exception in the West is some bituminous coal found in Colorado
extending into New Mexico. All of the coals in the Western U.S.,
including the Western bituminous coals, are characterized by low
chlorine contents, while the bituminous coals in the Eastern U.S. have
much higher chlorine contents. Therefore, the expected amount of ionic
mercury and consequently the expected capture in a scrubber will be
much higher for coals from the Eastern U.S. than from those in the
Western U.S.
Typical coal-fired power plant flue gas produced from combustion of
the bituminous coals found in the Eastern U.S. would contain the
following proportions of the mercury species: 60% ionic mercury, 38%
elemental mercury, and 2% particulate mercury. The particulate mercury
would be removed in the power plant's electrostatic precipitator. We
would expect the scrubber to remove 90 to 95% of the ionic mercury, and
none of the elemental mercury. The overall mercury removal in this
simple example would then be 56% (90% of the ionic and nearly 100% of
the particulate mercury removed). This example is in good agreement
with recent testing where, at three bituminous-fired power plants
studied by EPRI, the FGD system removed 43 to 51% of the mercury.
However, most of the coals from the Western U.S. when used in a
power plant produce much less ionic mercury, with typical estimates of:
25% ionic, 74% elemental, and less than 1% particulate. A scrubber on
this power plant would then only be expected to remove 90% of the ionic
and the electrostatic precipitator or bag house to remove nearly 100%
of the particulate mercury. Therefore, the total mercury removal would
be only 23.5%. The ICR database shows that power plants burning low
rank coals ranged from near zero to 38% mercury capture without wet
scrubbers, and 11 to 56% on those plants with scrubbers.
A problem with capturing mercury in wet FGD scrubbers has been
discovered through analysis of the EPA Information Collection Request
database. In some power plants that were tested for mercury species and
also had wet SO2 scrubbers, the apparent high capture of
ionic mercury was offset by an increase in the amount of elemental
mercury as the flue gas moved through the scrubber. So, while the ionic
mercury appeared to be captured at efficiencies approaching 95%, some
of the ionic mercury, after being captured in the scrubber, was
converted back to the elemental form, which evaporated from the
scrubber and was then emitted as elemental mercury.
An example may help explain the effect. Say that, before the
scrubber, there are 10 micrograms (one millionth of a gram or 2
billionth's of a pound) of mercury in one cubic meter (about 35 cubic
feet) of flue gas. Furthermore, let's say that 60% of that is ionic and
the balance is elemental, or 6 micrograms per cubic meter ionic and 4
micrograms per cubic meter of elemental mercury. In a power plant that
shows this mercury release phenomena, we might see less than 0.1
microgram per cubic meter of ionic mercury at the stack exit, an
apparent capture of 98.3% of the ionic mercury. But, we see the stack
exit containing maybe 5.5 micrograms per cubic meter of elemental
mercury, an increase of 37.5%.
The elemental mercury is not being captured but is actually
increasing across the scrubber. When looking at the total mercury, the
10 micrograms per cubic meter at the scrubber inlet is reduced to only
5.6 micrograms per cubic meter (5.5 elemental and 0.1 ionic) at the
stack, a total reduction of only 44%. The only logical explanation to
explain these example numbers is that some of the captured ionic
mercury is being re-released as elemental mercury. In this case, the
ionic mercury is only being captured at 73%, when the re-released
mercury is included.
This scrubber mercury re-release is not well understood at this
point. An analysis by EPRI notes a correlation between an increase in
the amount of fly ash captured in the scrubber and an increase in the
mercury re-release. Further work by EPRI on a bench-scale scrubber
shows that this phenomenon is transient, and it is not easy to predict
when it will occur. Additionally, private testing by Southern Company
at our DOE-sponsored flue gas scrubber at Georgia Power's Plant Yates,
south of Atlanta, has shown that this effect is present at some times,
and not present at others. The significance of this effect is that the
overall capture of mercury by a wet scrubber may be less over time than
a short test period would indicate. Further research of this phenomenon
is needed.
Most of the previous discussion assumes that the FGD process used
is the wet limestone, forced-oxidation scrubber. Another process for
SO2 control, used widely for low sulfur Western coals, is a
lime-based spray dryer followed by a bag house that collects both the
reacted lime along with all of the coal ash. The EPA Information
Collection Request testing in 1999 indicates that this spray dryer-bag
house FGD process may give very high mercury removals with bituminous
coals. However, this is a rare application of this technology, and
unfortunately is not widely applicable to all bituminous coal
applications. The technology is only effective for SO2
control for low sulfur coals, is more expensive than the alternatives,
and creates a large waste stream that has to be carefully handled for
disposal. While this approach may be used in a few power plants burning
Eastern bituminous coal for combined SO2 and mercury
control, I do not expect it to be very widely selected because of these
limitations.
Ironically, the best application of this FGD process is for Western
coals, but there it appears to make the mercury control worse than just
particulate control alone. That is, the use of a spray dryer-bag house
system on most low rank coals (sub bituminous and lignite) is normally
the best engineering and low-cost FGD solution for plants burning these
coals for SO2 control, but the evidence suggests that it may
worsen the mercury collection efficiency as compared to the use of a
bag house alone. For example, EPA states that sub bituminous coal
plants in the ICR database with only bag houses average 72% mercury
control, while those with a bag house and a spray dryer for
SO2 control average only 24% mercury removal.
Various technologies are being investigated to attempt to further
oxidize elemental mercury to ensure higher removal in a FGD system.
Chemical injection, plasma discharges, and dedicated catalysts are all
being tested and developed. These approaches are all under development,
and only slow progress is being made.
Selective Catalytic and Non-Catalytic Reduction (SCR & SNCR)
NOX Controls
One of the most intriguing possibilities is the ability of
NOX control selective catalytic reduction (SCR) systems to
enhance the amount of ionic mercury in the flue gas. A report on
research done by a large German utility company in the early 1990's
claims that the catalyst used in a SCR system was effective in
converting a high fraction of the elemental mercury to the ionic form,
which was then captured in FGD equipment. The German claim was that the
SCR catalyst changed the chlorine chemistry, making it more likely to
convert elemental mercury to ionic mercury.
Based on this German research, EPA originally assumed that any
power plant equipped with a SCR and FGD, burning any type of coal,
would see: (1) almost all of the elemental mercury converted to ionic;
(2) the ionic mercury captured in a scrubber in a high proportion; and
(3) no mercury re-released from the FGD process--all adding up to an
estimate of an overall 95% reduction in mercury emissions from those
plants. A 95% mercury capture would require that the SCR catalyst be
97.5% effective in converting elemental to ionic mercury. Furthermore,
the FGD system would have to be 97.5% effective in removing the ionic
mercury--that is, not only does the scrubber have to perform at least
as well on mercury as the SO2 (even though the mercury is
one-millionth times as concentrated), but no re-release of mercury can
occur. EPA's assumptions were highly optimistic and recent power plant
testing has shown these assumptions are not always true.
SCR catalyst degrades over time in its performance to reduce
NOX, requiring replacement every three to five years. The
catalytic activity is reduced by exposure to flue gas, either by
poisoning of the catalyst active ingredient from the chemicals in the
flue gas or by physical plugging of the catalyst surface by ash
particles. It is not known, at present, how this catalyst deactivation
affects its ability to oxidize mercury. The mercury oxidation of the
catalyst could be reduced at the same rate as the NOX
reduction, or it might be slower or faster. EPRI testing has only
looked at two power plants and only in two ozone seasons (May 1 to
September 30). So we have limited information, both in the number of
plants tested and the time between tests. Therefore, any estimate of
the long-term potential for co-benefits of SCR and FGD for mercury
reductions must consider the possibility of catalyst aging and the
subsequent potential loss in mercury oxidation.
For the lower rank coals, and particularly those found in the
Western U.S., this SCR mercury oxidation does not appear to occur.
Given the German claim of the effect being based on higher chlorine
content, this is not much of a surprise. The low rank coals are
typically low in chlorine, and to make matters worse, the ash of these
coals is alkaline, so that whatever chlorine that is present, being an
acid, is usually neutralized by the fly ash before it can ever reach
the SCR catalyst. Testing in an EPRI program sponsored by utilities
(including Southern Company) along with the Department of Energy (DOE)
and the EPA has shown that mercury reduction in low rank coals do not
seem to be helped by the addition of a SCR system. Since the majority
of the mercury in the flue gases from these coals in the elemental
state, the addition of any type of FGD system does not appear to
control mercury emissions to any significant degree. In other words,
for low rank coals (typically Western U.S. coals), we do see modest
benefits on mercury control by adding wet FGD systems, but do not see
any mercury co-benefits from adding an SCR to the power plants burning
these coals. EPA has also seen the results of the testing, and we think
that they have revised their assumptions about co-benefits for lignite
and sub bituminous coal to reflect this new knowledge, that is, there
are only modest mercury reductions based on co-benefits of
NOX and SO2 reductions for these coals.
At the beginning of the MACT development process, EPA had assumed
that selective non-catalytic reduction (SNCR) systems would contribute
to increased mercury removal, and explicitly had assumptions about its
performance in their models. SNCR uses ammonia injection at elevated
temperatures (1900-2400 deg.F) to reduce NOX without the use
of a catalyst. Two years of testing have shown that this NOX
reduction technology has no influence on mercury control in any plant
with any coal rank. Finally, we think that the Agency has conceded this
point and we hope that they no longer count SNCR as having any
influence on mercury control.
Summarizing the current state of knowledge of controlling mercury
via co-benefits of SO2 and NOX reductions, there
are only a handful of power plants that have been tested for short time
periods. Given this limited amount of data, we think that for
bituminous coals the mercury reductions with a SCR and FGD will
probably be between 80-90% for the best case, and that for sub
bituminous and lignite coals the reduction will be a modest 20%. These
estimates are optimistic taking into account the previous discussions
of catalyst aging in SCR systems and mercury re-release for FGD
systems, and are likely to be reduced even further in the future. We
think that EPA is currently using an estimate of 90% for bituminous
coals and something less than 90% for lignite and sub bituminous.
Activated Carbon Injection
The second near-commercial technology for mercury control from
coal-fired power plants is activated carbon injection (ACI). Activated
carbon is a specially prepared product of coal or biomass that is able
to adsorb many chemicals from gases or liquids. One of the primary uses
of activated carbon is the treatment of drinking water. Water filtering
systems sold for home use in home improvement stores are typically
cartridge systems that include activated carbon as part of the filter.
Activated carbon is being used currently to remove mercury from the
flue gases from municipal, medical, and hazardous waste incinerators.
In those applications, activated carbon can routinely collect over 90%
of the mercury from the flue gas. However, the mercury concentrations
in the stack after the activated carbon treatment in these incinerators
are typically higher than that found in coal flue gas before treatment.
That is, the amount of mercury in every cubic foot of incinerator stack
gases after the control system using activated carbon is typically 5 to
10 times the amount in untreated coal flue gases from power plants.
Another way to look at a comparison between incinerators and power
plants is that most every power plant would meet the incinerator
mercury regulations without any control technologies. Simply,
incinerator mercury control by activated carbon stops where power plant
flue gases begin. Therefore, it is not useful to use the experience of
activated carbon in incinerators to inform the debate on its use in
power plants.
The design of activated carbon injection for mercury control relies
upon the existing equipment used to remove fly ash from the flue gas to
also remove the added activated carbon. There are many side issues
associated with the use of activated carbon in this mercury process
approach, including contamination of the fly ash with carbon and
interruption of the normal fly ash control by the added load of
activated carbon. The injection ahead of electrostatic precipitators,
which are in use by about 80% of the U.S. coal power plants, may
require large amounts of activated carbon to achieve reasonable mercury
control. The carbon will contaminate the fly ash making it unusable for
recycling and may threaten the performance of the electrostatic
precipitator for its intended use of removing fly ash. Injection of
activated carbon in a bag house will not need as much activated carbon
as an electrostatic precipitator, but will also contaminate the fly
ash.
There have been only a handful of tests on the use of activated
carbon to control mercury from coal-fired power plants. The very first
test at full-scale in the United States was performed at a Southern
Company power plant, Alabama Power's E.C. Gaston Unit 3, located in
Wilsonville, Alabama. This was the first in a series of four power
plant tests in a sequence performed by ADA-Environmental Solutions of
Littleton, Colorado. The test program was sponsored by DOE's National
Energy Technology Laboratory (NETL) with significant co-funding by
participating utilities and vendors. All of these four sites are
somewhat unique, and unfortunately do not well represent the nation's
power plant fleet.
Gaston Unit 3 is one of only four power plants in the U.S. that
have an advanced particulate control system that consists of a small
bag house installed downstream of the existing electrostatic
precipitator. This arrangement, known as COHPAC TM, is a
patented EPRI invention. The activated carbon can be injected between
the electrostatic precipitator and the bag house. The electrostatic
precipitator collects over 95% of the fly ash, while the bag house
collects the remainder of the ash and the activated carbon. This
approach to activated carbon injection avoids contamination of the fly
ash and does not jeopardize the operation of the electrostatic
precipitator with additional carbon loading. The bag house is a large
filter, which has hundreds of fabric bags that separate the solid ash
and carbon from the flue gases, much like the paper bag in a household
vacuum cleaner. Because the activated carbon can sit on the surface of
the bags for several minutes and see a substantial amount of flue gas,
it can effectively collect more mercury from the flue gas than
injection into an electrostatic precipitator.
The activated carbon injection testing at Gaston, which burns an
Eastern U.S. bituminous coal, ended with a seven-day test of mercury
control, where the average mercury reduction over that time period was
just under 80%, with a high of over 90% and a low of only 36%. This was
a short-term test and probably does not reflect the ability of this
system to always perform at this level. We found in this testing that
the bag house at Gaston is not big enough to accommodate the amount of
activated carbon needed to consistently achieve 90% mercury control for
even just one week of testing. The testing was promising and DOE/NETL
has funded a follow-on project that will test the mercury control at
this location for one calendar year. This length of testing will allow
a better estimate of the potential mercury control from this technology
over the course of that one year. We are just starting this longer term
testing, and the initial results were presented at an international
pollution control conference sponsored by DOE, EPA, and EPRI just two
weeks ago here in Washington. The initial results are not encouraging--
we cannot repeat the performance of the seven-day test performed in
2001. The electrostatic precipitator ahead of the bag house at Gaston
Unit 3 is not performing as well as it was during the earlier testing,
and we cannot inject much activated carbon into this system without
causing damage to the bag house. Two conclusions can be drawn from the
first few weeks of operation of the long-term testing: (1) the bag
house at this unit is simply not big enough to handle both the fly ash
and carbon loading over all operating conditions, and (2) the 80%
average mercury control seen in the earlier one week test cannot be
sustained over the long term. It may be possible to achieve levels
higher than 80% in other power plants with this configuration, assuming
that the additional capital investment is made to build a large bag
house. Again, this is a test at a power plant burning Eastern
bituminous coal.
The three other tests of full-scale mercury control using activated
carbon in the joint industry-DOE project all involve the injection of
activated carbon into the inlet of an electrostatic precipitator. The
first electrostatic precipitator injection test was performed at
Wisconsin Electric's (now We Energies) Pleasant Prairie Power Plant,
which burns a Western U.S. sub bituminous coal from the Powder River
Basin in Wyoming and Montana. This unit has a large electrostatic
precipitator that is likely to be able to handle the additional
particle loading from the activated carbon. The test that occurred over
one to two weeks was able to achieve a mercury control of between 60
and 70%, but notany higher, regardless of the amount of carbon injected
into the system. The logical conclusion from the testing seems to
indicate that there is a chemical limitation on the amount of mercury
control from low rank coals like lignite and sub bituminous, and maybe
for Western U.S. bituminous coals from Colorado and New Mexico. It
appears that, similar to the SCR oxidation of mercury, the activated
carbon needs sufficient chlorine in the flue gas to collect the
mercury. Again, this result was over a very limited time span test and
may not be repeatable over a yearlong period. Longer term testing of
this approach in several power plants needs to be performed before any
judgment of the mercury performance can be reliably made.
An additional consequence became clear during the test at We
Energies' Pleasant Prairie Power Plant. This site is able to sell all
of the fly ash it produces for recycling into concrete. The activated
carbon made the ash not usable for this purpose during the test period,
but also contaminated the ash for about four weeks after carbon
injection was discontinued. Southern Company declined a similar test at
one of our sub bituminous coal plants, due to the expense of lost ash
sales plus the added ash disposal costs.
The other two tests of activated carbon injection into
electrostatic precipitators for mercury control were both performed in
Massachusetts, at PG&E National Energy Group's Salem Harbor and Brayton
Point power plants. Salem Harbor is peculiar in that it produces a
large fraction of unburned coal particles that persist into the
electrostatic precipitator, possibly a result of the large amount of
South American coal being burned there. This high level of carbon
produced seems to remove a significant amount of mercury, with a
baseline removal ranging from 87 to 94% with one coal, but dropping to
50 to 70% with a second coal, all even before activated carbon
injection. The activated carbon injection was able to increase the
mercury capture to over 90%. Of course, this testing has shown that a
change of coal supply can dramatically change the mercury baseline
performance and the subsequent increased capture by activated carbon
injection.
Brayton Point is also a peculiar arrangement with two electrostatic
precipitators in series. In the DOE test, activated carbon was injected
between the two electrostatic precipitators, much like the injection
between the ESP and bag house at the Gaston station. The baseline
mercury removal, that is, the removal before activated carbon injection
started, was 90.8%. This is very high as compared to historical data
from that unit that recorded baseline mercury removals of 29 to 75%.
The results in the ten days of testing suggest that, for short periods,
the injection of activated carbon can increase the mercury removal from
a baseline of 90.8% to 94.5% with the addition of activated carbon (10
pounds carbon injected for every million cubic feet of flue gas).
Again, the short time of the test and the potential change in behavior
with a change in coal supply makes it hard to extrapolate this
performance much beyond the actual period of testing.
All of the electrostatic precipitator tests of activated carbon
injection to date have involved relatively large, oversized equipment
where the additional burden of collecting the injected activated carbon
did not impact the operation, at least in the tests of under two weeks
duration. For the same mercury collection efficiency as a COHPAC
TM bag house, the added carbon cost is substantial enough to
justify the capital investment to build the bag house.
Another--potentially large--problem with this technology is that
the supply of activated carbon is currently not sufficient to support
any significant use for utility mercury control. I have publicly stated
that, due to current uncertainties, Southern Company may use anywhere
between 500 tons per year to 100,000 tons per year of activated carbon.
The major U.S. manufacturer of activated carbon, Norit Americas, based
in Atlanta, Georgia, have told us that they could supply an additional
20,000 tons per year with their existing capacity. Without long-term
commitments from buyers, the activated carbon suppliers will very
likely not make the needed investments to ensure that a large demand
from the U.S. utility market could be met. In the 1970's, the activated
carbon industry built capacity in anticipation of clean water
regulations and those investments resulted in a severe price decrease
caused by oversupply, when the demand did not appear. The activated
carbon suppliers are not likely to make the same speculative capital
investments today. Add to this reluctance to invest ahead of demand the
fact that it will likely take at least five years to design, finance,
permit, and build activation carbon production facilities, and it
becomes apparent that, if activated carbon injection becomes the
technology of choice for power plant mercury control, the supply will
not be available at the beginning.
There may be foreign supplies of activated carbon. As discussed at
a recent conference, there may be about 50,000 to 60,000 tons per year
available from a major European supplier. Also, China has started
supplying activated carbon into the U.S. market, but initial experience
with this material has shown quality control problems with its
performance. All in all, there may be sufficient carbon available to
supply a small part of the industry with today's global supply, but
there is not enough supply for any major use across the nation by the
utility industry.
In early modeling efforts by EPA on the performance of activated
carbon, the assumptions made about performance and the actual amount of
activated carbon were grossly optimistic. The Agency used some
estimates made by DOE in 1999, and the subsequent testing at full scale
power plants has demonstrated that the performance is not as good as
the earlier estimates. We think that the current set of performance and
cost numbers offered by the Utility Air Regulatory Group in the MACT
Working Group are the best estimate for mercury control processes using
activated carbon.
In summary, the limited testing of activated carbon injection for
power plant mercury control does not represent the average
configuration of the U.S. power plant fleet, and the short-term tests
that have taken place only represent what a well-controlled and well-
managed test period performance could be--in other words, are likely to
be close to the best case. Additional testing at the Southern Company
plant has already shown that the earlier performance cannot be matched
at this moment. Certainly additional testing, including long-term tests
of at least eight months are needed to understand what the actual
performance of activated carbon injection over longer times would be,
with the wide variety of coals in use today. At this moment, the DOE/
NETL is evaluating a number of proposals from utilities, vendors, and
research contractors to test activated carbon for longer periods of
time on a variety of plants, especially those that burn low rank coals.
With sufficient capital investment to build a COHPAC TM
bag house large enough to handle both the fly ash and activated carbon,
short-term performance of 90% mercury removal with bituminous coals may
be possible, but, across the industry, an average removal of 80% is
more likely to be achieved with today's technology. This estimate is
based on only one power plant, tested for only seven days, however. It
appears that low rank coals, such as lignite and sub bituminous coals,
may have a limit of 60-70% mercury removal, regardless of the amount of
activated carbon used or whether a bag house has been installed. Again,
only one power plant has been tested for less than two weeks to
establish this estimate. Under certain circumstances, activated carbon
injection into a large ESP may be able to get incremental mercury
control, but only two power plants have been tested for less than two
weeks. Finally, the supply of activated carbon is not sufficient today
to accommodate a substantial demand from the utility sector and it may
take five years to bring new activated carbon production facilities on
line.
Other Technologies
There are other technologies that show some promise in controlling
mercury emissions from power plants, but they are all still research
projects and are nowhere close to commercialization. Some of the multi-
pollutant processes being developed do claim that mercury control is
also removed along with SO2, particulates, and
NOX. While this may be true, there are large questions about
the costs, reliability, and long-term performance of these
technologies. Most of these multi-pollutant processes make either
fertilizer or acid chemical feedstocks from the NOX and
SO2, and the ability to sell either of these waste streams
in the future is questionable. The larger the penetration of these
technologies into the utility market, the more of the byproducts that
are produced, quickly over-saturating any potential market.
Possible future technologies that are being researched include
capture of mercury by gold-plated surfaces, the use of chlorine
addition to low rank coals to increase the mercury oxidation, injection
of sulfur compounds to change the elemental and ionic mercury gases to
solid sulfides that can be captured in the existing particulate control
devices. Additionally, a large number of alternative sorbents to
replace activated carbon, either with a less costly material cost or
improved performance with less material injected, are under
development. Unfortunately, we cannot predict whether these efforts
will succeed, and we cannot base national energy policy on the hope
that something is invented in time to produce the perceived needed
level of mercury control.
Timing of Mercury Reductions
The timing of mercury reductions required, whether by regulations
under a MACT provision or by a legislative process, needs to take under
consideration both the state of knowledge about mercury control and the
ability of the nation's utility industry to install the required
controls. Already, in the installation of NOX controls for
the 2003 summer ozone season, we have experienced some labor shortages
and tight supplies of steel, cranes, and auxiliary equipment such as
fans, pumps, electric motors, switchgear, etc. If mercury control
proceeds under a MACT regulation, every coal-fired power plant will
have to meet the stated emissions requirements, and depending on the
technologies being used, we expect shortages of steel, bag house bags,
labor, and auxiliary equipment, not to mention the activated carbon
supply issues discussed earlier. Southern Company estimates that the
time required to install mercury controls under MACT would be at least
seven years, and the time needed for the additional NOX and
SO2 controls in Clear Skies would take probably eight to
nine years.
Estimates of Benefits of Utility Mercury Reductions
EPRI and EPA are both engaged in research to attempt to predict the
net effect on human health from reductions in emissions from U.S. coal-
fired power plants. EPRI has just published their initial findings, and
we think that EPA is working on similar model predictions. In the EPRI
study, mercury deposition on the continental U.S. is predicted using a
global mercury source and deposition model. The results indicate that
the majority, around 70%, of the mercury falling on the U.S. is from
sources outside the U.S. Additionally, this study predicts that U.S.
utility emissions are estimated to contribute less than 8% of the
mercury depositing in the U.S. This result is significant, because it
indicates that reductions of mercury emissions from domestic utility
sources will have a limited response on the amount of mercury
depositing. In other words, since most of the mercury falling on the
U.S. comes from overseas, controlling domestic utility emissions can
have only a limited impact. The EPRI study goes on to estimate the
change in human exposure from significant reductions in utility mercury
reductions. The only significant route of exposure to humans is through
the consumption of large fish, captured in the wild. By estimating the
change in U.S. deposition from reductions in utility emissions, the
change in mercury in aquatic systems, and subsequently in fish, can be
found. Taking the analysis one step further, EPRI has estimated the
change in exposure to humans in the U.S. from utility mercury
reductions.
The EPRI study looked at mercury reductions in a Clear Skies Act
approach and in a mercury MACT regulation scenario. The results
indicate under the Clear Skies approach, in the year 2020, mercury
deposition in the continental U.S. would be reduced by an average of
1.5%, exposure of women of childbearing age to mercury would be reduced
by 0.5%, and the fraction of the population above the reference dose
for mercury would be reduced by only 0.064%. In the MACT approach, also
for the year 2020, mercury deposition would be reduced by 1.2%,
exposure of women of childbearing age to mercury would be reduced by
0.4%, and the fraction of the population above the reference dose would
be reduced by 0.055%. Since U.S. utility emissions are only a small
contributor to mercury in the environment, it is not surprising that
significant reductions in those emissions will not greatly affect human
exposure. One significant difference in the two approaches is that the
present value incremental cost for mercury controls by 2020 is
estimated to be about $6 billion for CSA and $19 billion for MACT.
Summary
There are no commercially available technologies for mercury
controls for coal-fired power plants. There are systems in use in the
waste incinerator industry, but the EPA requirements for mercury
control for incinerators allow emitted concentrations to be five to ten
times higher than uncontrolled coal power plant emissions. In an
engineering sense, the low concentrations mean that you have to work
that much harder to get each molecule of mercury. NOX and
SO2 stack concentrations are one million times higher than
mercury, so you have to work one million times harder to collect
mercury as compared to either NOX or SO2.
There are two near-commercial mercury control technologies at
present: co-control by FGD systems, with possible beneficial mercury
chemical changes from SCR systems on plants burning bituminous coals,
and the injection of activated carbon into existing or new particulate
control devices, either ESPs or bag houses.
Plants burning bituminous coal from the Eastern U.S. which have
installed SCR systems and wet scrubbers are likely to have between 80
and 90% mercury control in the beginning. There are large uncertainties
about the potential adverse scrubber chemistry that could re-release
captured mercury and also about the extent of SCR catalytic mercury
oxidation over time, so it is likely that these estimates may decrease
as we learn more.
For low rank coals such as sub bituminous and lignite (along with
bituminous coal from the Western U.S.), the SCR systems do not appear
to have any beneficial effects on mercury chemistry, probably due to
the low chlorine content of the coals. Additionally, the addition of a
wet FGD scrubber system may increase mercury control slightly, say by
20%, but the addition of a spray-dryer FGD system may even decrease the
mercury removal as compared to the pre-FGD mercury removal performance.
Activated carbon tests to date have been short, less than two
weeks, and have shown some promise, but also some difficulties. The
only long-term test that is being performed is at Southern Company's
Plant Gaston, and the year long test is just beginning. The limited
data from this one short test suggests that activated carbon injection
into a COHPAC TM bag house installed at a plant burning
bituminous coal may be able to achieve short-term performance of 90%
mercury removal, but an average across a year is more likely to be
around 80%. We do not know what operation problems may occur after an
extended period of activated carbon injection, but even at the
beginning of the year long test, we are not able to match the previous
short term performance.
Activated carbon injected into an electrostatic precipitator at a
plant burning Powder River Basin sub bituminous coal has shown mercury
removal of 60-70%, but only for a short test, and with serious
consequences for ash sales and disposal. The chemistry of low rank
coals like these may limit the final mercury removal that can be
achieved with activated carbon. Again, based on this one power plant
test for a short period, it is likely that a bag house and activated
carbon injection would still only achieve 60-70% mercury removal on
these coals.
Activated carbon supply is also an unanswered question. Activated
carbon vendors have estimated the U.S. utility market may be between
500,000 and 1,500,000 tons per year. Between domestic supply and spare
European capacity, there may be up to 150,000 tons per year available
today. Without firm commitments, the suppliers are unwilling to make
the investments to increase the supply, indicating that widespread use
by the utility industry may create a worldwide shortage of activated
carbon. Given that it takes roughly five years to bring a new activated
carbon production facility on line, the prospects for widespread
availability of activated carbon may be questionable.
In addition, the shortages encountered during the installation of
NOX controls over the last several years have shown that
shortages of labor, steel, cranes, and auxiliary equipment can occur,
and installation of mercury controls under a MACT regulation or
installation of more NOX and SO2 controls will
surely cause even greater material and labor shortages. The only way to
alleviate the shortages is to extend the required performance date to
install the equipment. These shortages could spill over into other
industries and cause price increases across the board.
There are other technologies under development for mercury control,
but they are all very much still in a research stage. Various multi-
pollutant processes are being touted, but they suffer from questions
about performance, cost, and waste disposal issues. Other processes to
specifically affect or capture mercury are also under development, but
are at least eight to fifteen years away from deployment, if they work
at all.
More tests and longer tests are needed to be able to reliably
estimate performance and design the appropriate equipment and processes
for mercury reductions in power plants with different equipment
installed and burning different ranks of coal. The Department of Energy
is currently evaluating a number of proposals from the utility
industry, vendors, and research organizations to test a wide variety of
plants and coals for mercury control, over a longer test period. The
electric power industry, along with EPRI and equipment vendors, is
engaged in a large, coordinated effort to develop and optimize cost-
effective mercury emission reduction processes.
EPRI modeling suggests that U.S. utility emissions of mercury are
only a small contributor to deposition of mercury in the continental
U.S. Significant reductions of those emissions, either under a CSA or
MACT approach, will only reduce deposition in the U.S. by 1.5%, and
will only decrease exposures of the most sensitive population of women
of childbearing age by 0.5% in 2020, as compared to 1999.
The utility industry does not have proven technologies to reduce
mercury emissions, but we know that some reductions will occur as
SO2 and NOX control systems are installed, either
under Clear Skies or business-as-usual. The industry does not hold the
position that mercury reductions should not occur, but asks that right
timeline should be followed, one that considers the practical aspects
of the cost and impact of making these reductions. Mercury emission
reductions that are required before the technology has been fully
developed will lead to significantly increased costs, to likely fuel
switching from coal to natural gas, and to possible disruption of the
nation's energy supply.
Mr. Strickland. Thank you, Mr. Chairman.
Mr. Whitfield. Thank you, Mr. Strickland.
I want to thank all of the panel members for taking time
from their busy schedules for joining us today on this
important hearing on the future options for generation of
electricity from coal. As it has been said, it is our most
abundant resource. And we are going to continue to be dependent
upon it. Your testimony has gone a long way in helping us focus
in on some very important issues. So I want to thank you and
want you to know that we may very well be coming back to you
from time to time for additional comments to solve some of
these problems.
So, with that, this hearing will be adjourned.
[Whereupon, at 4:51 p.m., the hearing was adjourned.]
[Additional material submitted for the record follows:]
Southern Company
July 10, 2003
The Honorable Rick Boucher
House of Representatives
Washington, DC 20515
On June 24 when I testified before the House Committee on Energy
and Commerce's Subcommittee on Energy and Air Quality you asked if the
tax incentives in HR 1213 would be adequate to encourage Southern
Company to build a new advanced coal-fired power plant instead of a
natural gas-fired plant. I agreed to examine the question and get back
to you. Unfortunately, the answer is ``no'' for our specific situation.
Southern Company's location, relatively close to natural gas
supplies and somewhat removed from most coal supplies, makes natural
gas electric generation more competitive than it may be in other areas
of the country. New coal-fired generation is more competitive in
locations that are nearer large coal supplies and further from natural
gas supplies.
We strongly believe that tax incentives similar to those in HR1213
are needed to encourage the use of advanced coal-based power
generation. My testimony and that of others before the Subcommittee
outline why this is critically important. Southern Company's specific
situation should not be a basis for reducing these efforts.
If I can be of further assistance please do not hesitate to call.
Sincerely,
Randall E. Rush
Southern Company