[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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                            WASHINGTON : 2003
____________________________________________________________________________ 
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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.
---------------------------------------------------------------------------
    \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
---------------------------------------------------------------------------
    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:
---------------------------------------------------------------------------
    \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
---------------------------------------------------------------------------
    \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.
---------------------------------------------------------------------------
    \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.
---------------------------------------------------------------------------
    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
---------------------------------------------------------------------------
    \3\ Remarks of Energy Secretary Spencer Abraham to the National 
Coal Council on November 21, 2002.
---------------------------------------------------------------------------
    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.
---------------------------------------------------------------------------
    \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.
---------------------------------------------------------------------------
    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
---------------------------------------------------------------------------
    \5\ NETL, Carbon Sequestration, Tehchnology Roadmap and Program 
Plan, March 12, 2003.
---------------------------------------------------------------------------
    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?
---------------------------------------------------------------------------
    \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.
---------------------------------------------------------------------------
    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
---------------------------------------------------------------------------
    \7\ See, eg, Lyon, Voluntary versus Mandatory Approaches To Climate 
Change Mitigation, Resources for the Future Issue Brief 03-01, February 
2003
---------------------------------------------------------------------------
    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
---------------------------------------------------------------------------
    \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.
---------------------------------------------------------------------------
    \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.
---------------------------------------------------------------------------
    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
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