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88–426PDF 2003

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

COMMITTEE ON ENERGY AND COMMERCE

W.J. ‘‘BILLY’’ TAUZIN, Louisiana, Chairman

MICHAEL BILIRAKIS, Florida

JOE BARTON, Texas

FRED UPTON, Michigan

CLIFF STEARNS, Florida

PAUL E. GILLMOR, Ohio

JAMES C. GREENWOOD, Pennsylvania

CHRISTOPHER COX, California

NATHAN DEAL, Georgia

RICHARD BURR, North Carolina

Vice Chairman

ED WHITFIELD, Kentucky

CHARLIE NORWOOD, Georgia

BARBARA CUBIN, Wyoming

JOHN SHIMKUS, Illinois

HEATHER WILSON, New Mexico

JOHN B. SHADEGG, Arizona

CHARLES W. ‘‘CHIP’’ PICKERING,

Mississippi

VITO FOSSELLA, New York

ROY BLUNT, Missouri

STEVE BUYER, Indiana

GEORGE RADANOVICH, California

CHARLES F. BASS, New Hampshire

JOSEPH R. PITTS, Pennsylvania

MARY BONO, California

GREG WALDEN, Oregon

LEE TERRY, Nebraska

ERNIE FLETCHER, Kentucky

MIKE FERGUSON, New Jersey

MIKE ROGERS, Michigan

DARRELL E. ISSA, California

C.L. ‘‘BUTCH’’ OTTER, Idaho

JOHN D. DINGELL, Michigan

HENRY A. WAXMAN, California

EDWARD J. MARKEY, Massachusetts

RALPH M. HALL, Texas

RICK BOUCHER, Virginia

EDOLPHUS TOWNS, New York

FRANK PALLONE, Jr., New Jersey

SHERROD BROWN, Ohio

BART GORDON, Tennessee

PETER DEUTSCH, Florida

BOBBY L. RUSH, Illinois

ANNA G. ESHOO, California

BART STUPAK, Michigan

ELIOT L. ENGEL, New York

ALBERT R. WYNN, Maryland

GENE GREEN, Texas

KAREN MCCARTHY, Missouri

TED STRICKLAND, Ohio

DIANA DEGETTE, Colorado

LOIS CAPPS, California

MICHAEL F. DOYLE, Pennsylvania

CHRISTOPHER JOHN, Louisiana

TOM ALLEN, Maine

JIM DAVIS, Florida

JAN SCHAKOWSKY, Illinois

HILDA L. SOLIS, California

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

RICHARD BURR, North Carolina

ED WHITFIELD, Kentucky

CHARLIE NORWOOD, Georgia

JOHN SHIMKUS, Illinois

Vice Chairman

HEATHER WILSON, New Mexico

JOHN SHADEGG, Arizona

CHARLES W. ‘‘CHIP’’ PICKERING,

Mississippi

VITO FOSSELLA, New York

STEVE BUYER, Indiana

GEORGE RADANOVICH, California

MARY BONO, California

GREG WALDEN, Oregon

MIKE ROGERS, Michigan

DARRELL ISSA, California

C.L. ‘‘BUTCH’’ OTTER, Idaho

W.J. ‘‘BILLY’’ TAUZIN, Louisiana

(Ex Officio)

RICK BOUCHER, Virginia

(Ranking Member)

ALBERT R. WYNN, Maryland

THOMAS H. ALLEN, Maine

HENRY A. WAXMAN, California

EDWARD J. MARKEY, Massachusetts

RALPH M. HALL, Texas

FRANK PALLONE, Jr., New Jersey

SHERROD BROWN, Ohio

BOBBY L. RUSH, Illinois

KAREN MCCARTHY, Missouri

TED STRICKLAND, Ohio

LOIS CAPPS, California

MIKE DOYLE, Pennsylvania

CHRIS JOHN, Louisiana

JOHN D. DINGELL, Michigan

(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)

(1)

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.

2

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,

3

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 tolVerDate 11-MAY-2000 09:32 Sep 11, 2003 Jkt 000000 PO 00000 Frm 00007 Fmt 6633 Sfmt 6633 88426.TXT HCOM1 PsN: HCOM1
4

erate 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.

5

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 efVerDate 11-MAY-2000 09:32 Sep 11, 2003 Jkt 000000 PO 00000 Frm 00009 Fmt 6633 Sfmt 6633 88426.TXT HCOM1 PsN: HCOM1
6

fort 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 lowend, 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 coalbased 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.

7

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.

8

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:]

9

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

10

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.

11

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.

12

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 beVerDate 11-MAY-2000 09:32 Sep 11, 2003 Jkt 000000 PO 00000 Frm 00016 Fmt 6633 Sfmt 6602 88426.TXT HCOM1 PsN: HCOM1
13

come 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

14

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

15

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.

16

The Department envisions that FutureGen would be sized to generate the equivalent of approximately 275 megawatts of electricity, roughly equal to an average midsize 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

17

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

18

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

19

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 manuVerDate 11-MAY-2000 09:32 Sep 11, 2003 Jkt 000000 PO 00000 Frm 00023 Fmt 6633 Sfmt 6621 88426.TXT HCOM1 PsN: HCOM1
20

facturers 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

21

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

22

a byproduct. Selective Catalytic Reduction, which is an effective means for NOX con- trol, 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

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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 landuse 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

24

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

Roadmap Performance Targets Reference 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-benefits’’ 90% 95%

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

Roadmap Performance Targets Reference 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’’)

25

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.

Coal Technology Platforms

RD&D Spending

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)

Technology Program Administration

FY 2004 Request

CURC Roadmap

Annual R&D Budget1

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

1This 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 demVerDate 11-MAY-2000 09:32 Sep 11, 2003 Jkt 000000 PO 00000 Frm 00029 Fmt 6633 Sfmt 6621 88426.TXT HCOM1 PsN: HCOM1
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onstration 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

27

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

28

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

29

1Market-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

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 longterm 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 nonprofit, 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.

30

2The 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.

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:

• 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:

31

• 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 coalfired 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

32

3 Coal-Related Greenhouse Gas Management Issues, National Coal Council, May 2003

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.’’

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

33

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.

34

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 spe- cific 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

35

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.

36

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?

37

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?

38

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 bellshaped 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.

39

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 mil- lion. 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

40

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.

41

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

42

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.

43

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

44

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.

45

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 cobenefit 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 coalfired 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?

46

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.

47

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 fullscale 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.

48

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 equipVerDate 11-MAY-2000 09:32 Sep 11, 2003 Jkt 000000 PO 00000 Frm 00052 Fmt 6633 Sfmt 6621 88426.TXT HCOM1 PsN: HCOM1
49

ment 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.

50

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

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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 onstream 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.

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And, as Eastman has proved through 20 years of experience, coal

gasifications can be operated at maximum efficiency with a highdegree 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.

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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 byproduct credits—are currently better for coal gasification than any other fossil fuelbased 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.

54

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 coalto-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.

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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.

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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.

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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°F and 2700°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 reVerDate 11-MAY-2000 09:32 Sep 11, 2003 Jkt 000000 PO 00000 Frm 00061 Fmt 6633 Sfmt 6621 88426.TXT HCOM1 PsN: HCOM1
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moved 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°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.

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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

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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.

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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.

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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 coalbased 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

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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

64

1The 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.

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 coalbased energy by 2020. There are specific targets for emissions of sulfur dioxide, nitrogen oxides, particulate matter and mercury, carbon dioxide management, byproduct 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.

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

65

2Market-Based Valuation of Coal Generation and Coal R&D in the U.S. Electric Sector, May

2002, EPRI-LCG.

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, coalbased 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).

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

66

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, artiVerDate 11-MAY-2000 09:32 Sep 11, 2003 Jkt 000000 PO 00000 Frm 00070 Fmt 6633 Sfmt 6602 88426.TXT HCOM1 PsN: HCOM1
67

cle 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 pulverVerDate 11-MAY-2000 09:32 Sep 11, 2003 Jkt 000000 PO 00000 Frm 00071 Fmt 6633 Sfmt 6621 88426.TXT HCOM1 PsN: HCOM1
68

ized 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 longterm 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.

69

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.

70

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 fullscale 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 opVerDate 11-MAY-2000 09:32 Sep 11, 2003 Jkt 000000 PO 00000 Frm 00074 Fmt 6633 Sfmt 6602 88426.TXT HCOM1 PsN: HCOM1
71

tions. 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 midterm 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.

72

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.

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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 largescale, 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.

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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 safetyrelated 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.

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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 oxyfuel 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 oxygenfired 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.

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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 incenVerDate 11-MAY-2000 09:32 Sep 11, 2003 Jkt 000000 PO 00000 Frm 00080 Fmt 6633 Sfmt 6602 88426.TXT HCOM1 PsN: HCOM1
77

tives, 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 buildup 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

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1 ‘‘The President’s Carbon Intensity Reduction Initiative,’’ keynote address by Dr. John

Marburger Director, Office of Science and Technology Policy, Executive Office of the President

at USDOE Conference on Carbon Sequestration, Alexandria, Va., May 6, 2003

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

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

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2 K. Caldeira et al., ‘‘Climate Sensitivity Uncertainty and the Need for Energy Without CO2

Emission,’’ Science 299, 2052 (2003). To put a 2 degree Centigrade warming in context, recall

that the global average temperature during the last ice age was only 5 degrees cooler than

today. 3 Remarks of Energy Secretary Spencer Abraham to the National Coal Council on November

21, 2002. 4Other 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.

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.

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

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.

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

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5 NETL, Carbon Sequestration, Tehchnology Roadmap and Program Plan, March 12, 2003.

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 preindustrial 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

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

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6 I will mention the Clear Skies Act only in passing in this testimony, with the hope that

NRDC will be afforded an opportunity to present our substantial concerns with this legislation

in greater detail at a future hearing.

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?

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

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7See, eg, Lyon, Voluntary versus Mandatory Approaches To Climate Change Mitigation, Resources for the Future Issue Brief 03-01, February 2003 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.

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

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

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 bindVerDate 11-MAY-2000 09:32 Sep 11, 2003 Jkt 000000 PO 00000 Frm 00086 Fmt 6633 Sfmt 6621 88426.TXT HCOM1 PsN: HCOM1
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9Figure 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.

ing 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.

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.

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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:]

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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 coalburning 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.

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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

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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 benchscale. 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

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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

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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

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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 imVerDate 11-MAY-2000 09:32 Sep 11, 2003 Jkt 000000 PO 00000 Frm 00094 Fmt 6633 Sfmt 6621 88426.TXT HCOM1 PsN: HCOM1
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pacts 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——

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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

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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

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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

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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.

96

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.

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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

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omy. 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.

99

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

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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 coalfired power plants is very much in its infancy. Some early efforts at measuring the

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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 cocontrol 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°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 Hg0.

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

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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.

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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,

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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°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

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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

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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 colVerDate 11-MAY-2000 09:32 Sep 11, 2003 Jkt 000000 PO 00000 Frm 00110 Fmt 6633 Sfmt 6621 88426.TXT HCOM1 PsN: HCOM1
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lecting 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 wellcontrolled 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

108

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.

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Summary

There are no commercially available technologies for mercury controls for coalfired 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.

110

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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