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74–322 PDF 2012

S. HRG. 110–1130 

COAL GASIFICATION TECHNOLOGIES AND THE 

NEED FOR LARGE SCALE PROJECTS 

HEARING 

BEFORE THE

SUBCOMMITTEE ON SCIENCE, TECHNOLOGY, AND 

INNOVATION 

OF THE

COMMITTEE ON COMMERCE, 

SCIENCE, AND TRANSPORTATION 

UNITED STATES SENATE 

ONE HUNDRED TENTH CONGRESS 

SECOND SESSION 

APRIL 9, 2008 

Printed for the use of the Committee on Commerce, Science, and Transportation 

( 

(II) 

SENATE COMMITTEE ON COMMERCE, SCIENCE, AND TRANSPORTATION 

ONE HUNDRED TENTH CONGRESS 

SECOND SESSION 

DANIEL K. INOUYE, Hawaii, Chairman 

JOHN D. ROCKEFELLER IV, West Virginia 

JOHN F. KERRY, Massachusetts 

BYRON L. DORGAN, North Dakota 

BARBARA BOXER, California 

BILL NELSON, Florida 

MARIA CANTWELL, Washington 

FRANK R. LAUTENBERG, New Jersey 

MARK PRYOR, Arkansas 

THOMAS R. CARPER, Delaware 

CLAIRE MCCASKILL, Missouri 

AMY KLOBUCHAR, Minnesota 

TED STEVENS, Alaska, Vice Chairman 

JOHN MCCAIN, Arizona 

KAY BAILEY HUTCHISON, Texas 

OLYMPIA J. SNOWE, Maine 

GORDON H. SMITH, Oregon 

JOHN ENSIGN, Nevada 

JOHN E. SUNUNU, New Hampshire 

JIM DEMINT, South Carolina 

DAVID VITTER, Louisiana 

JOHN THUNE, South Dakota 

ROGER F. WICKER, Mississippi 

MARGARET L. CUMMISKY, Democratic Staff Director and Chief Counsel 

LILA HARPER HELMS, Democratic Deputy Staff Director and Policy Director 

CHRISTINE D. KURTH, Republican Staff Director and General Counsel 

PAUL NAGLE, Republican Chief Counsel 

SUBCOMMITTEE ON SCIENCE, TECHNOLOGY, AND INNOVATION 

JOHN F. KERRY, Massachusetts, Chairman 

JOHN D. ROCKEFELLER IV, West Virginia 

BYRON L. DORGAN, North Dakota 

BARBARA BOXER, California 

MARIA CANTWELL, Washington 

MARK PRYOR, Arkansas 

CLAIRE MCCASKILL, Missouri 

AMY KLOBUCHAR, Minnesota 

JOHN ENSIGN, Nevada, Ranking 

JOHN MCCAIN, Arizona 

KAY BAILEY HUTCHISON, Texas 

GORDON H. SMITH, Oregon 

JOHN E. SUNUNU, New Hampshire 

JIM DEMINT, South Carolina 

JOHN THUNE, South Dakota 

(III) 

C O N T E N T S 

Page 

Hearing held on April 9, 2008 ................................................................................ 1 

Statement of Senator Ensign .................................................................................. 3 

Prepared statement .......................................................................................... 4 

Statement of Senator Kerry .................................................................................... 1 

WITNESSES

Childress, James M., Executive Director, Gasification Technologies Council .... 13 

Prepared statement .......................................................................................... 15 

Hawkins, David G., Director, Climate Center, Natural Resources Defense 

Council .................................................................................................................. 35 

Prepared statement .......................................................................................... 37 

Marburger III, Ph.D., Hon. John H., Director, Office of Science and Technology Policy, Executive Office of the President ............................................... 6 

Prepared statement .......................................................................................... 8 

Mudd, Michael J., CEO, FutureGen Alliance, Inc. ............................................... 30 

Prepared statement .......................................................................................... 31 

Novak, John, Executive Director, Federal and Industry Activities, Environment and Generation, Electric Power Research Institute ................................ 45 

Prepared statement .......................................................................................... 46 

Strakey, Jr., Dr. Joseph P., Chief Technology Officer, National Energy Technology Laboratory, U.S. Department of Energy ................................................ 24 

Prepared statement .......................................................................................... 26 

APPENDIX

Response to written questions submitted by Hon. John F. Kerry to Dr. Joseph 

P. Strakey, Jr. ...................................................................................................... 81 

Stevens, Hon. Ted, U.S. Senator from Alaska, prepared statement ................... 81 

(1) 

COAL GASIFICATION TECHNOLOGIES AND 

THE NEED FOR LARGE SCALE PROJECTS 

WEDNESDAY, APRIL 9, 2008 

U.S. SENATE, 

SUBCOMMITTEE ON SCIENCE, TECHNOLOGY, AND INNOVATION, 

COMMITTEE ON COMMERCE, SCIENCE, AND TRANSPORTATION, 

Washington, DC. 

The Subcommittee met, pursuant to notice, at 2:39 p.m. in room 

SR–253, Russell Senate Office Building, Hon. John F. Kerry, Chairman of the Subcommittee, presiding. 

OPENING STATEMENT OF HON. JOHN F. KERRY, 

U.S. SENATOR FROM MASSACHUSETTS 

Senator KERRY. The hearing will come to order. Thank you very 

much. I apologize to all for being delayed. Even though not very 

much is going on here, too much is going on here, if you get my 

drift. So I apologize for not being able to open this on time. 

Thank you very, very much for joining us today to discuss the 

Federal Government’s role in the deployment and development of 

carbon capture technology at coal-fired power plants. I’ve repeated 

this many times, but I think at each hearing it’s important to state 

clearly the urgent challenge that faces our country and, indeed, the 

planet, with respect to the issue of global climate change. 

We all know that last year the Nobel Prize-winning Intergovernmental Panel on Climate Change found that nations of the world 

have to reduce their greenhouse gas emissions somewhere in the 

range of 50 to 80 percent by mid-century in order to avert dangerous impacts of climate change. 

I don’t know how many of you have seen what, I think National 

Geographic produced, and probably Dow Chemical underwrote, the 

‘‘Six Degrees’’ film, which was on television recently, which was a 

very stark and, I thought, authoritative analysis of the various 

computer models, the science, and what that science tells us, what 

with each degree of warming we may or may not face. I can assure 

you if you haven’t seen it, it’s worth the time because it really depicts, in no uncertain terms, what options are staring us in the 

face, in the absence of adequate response to climate change. 

What is interesting is, that every time you sit down with scientists, I try to make a point of doing a fairly regular update and 

briefing, and that these are not the alarmist type. I think scientists 

by definition are conservative people. Because to be a qualified, capable scientist, you have to have a pedagogy and a protocol, and 

follow it pretty strictly, and subject your analyses to peer review. 

2 

And what is interesting, as Al Gore pointed out in his An Inconvenient Truth, the reality is that the evidence is coming back much 

faster in a compounding way. Scientific studies now on the table 

indicate that our task may be even more challenging then they all 

laid out only a year ago, with findings for which they won the 

Nobel Prize. The point I wanted to make about Al Gore is that I 

think there were 650 or 900, I can’t recall the exact figure, peerreviewed studies, all affirming our contribution to the problem and 

all affirming the man-made input. 

It’s really important to understand that for all of the doubters, 

and for all of the people who throw out sun spots and other kinds 

of theories, each of those has been disposed of within the scientific 

community. There is no peer-reviewed study whatsoever that tells 

us that a factor other than human beings’ activities are creating 

climate change, or what is creating it. That’s a twofold test. If 

you’re going to doubt, you’ve got to show what’s doing this, because 

everybody acknowledges it’s warming. And nobody can. 

What’s alarming to me is that about 3 or 4 weeks ago, we received evidence that the world may need to eliminate carbon emissions altogether, within a matter of decades. Zero emissions. This 

science shows that coal combustion is the largest, or one of the 

largest contributors to global climate change. 

So, we need to find a way, obviously, coal isn’t going to go away, 

we all understand that. We know the reserves, we know the numbers on China, India, ourselves, South Korea, et cetera, so coal is 

not going away. It’s cheap and it’s abundant, and here in America 

we have enormous reserves, which people want to be able to use. 

In China, we know, on average they’re building about one pulverized coal-fired power plant per week. And that coal accounts for 80 

percent of their CO2 emissions. No matter what happens, with respect to all the efforts to reduce, China is going to equal the United 

States and surpass it in emissions within the next 10 years. 

So, China, I say this clearly to China and to others listening, 

China cannot consider itself a simple, old, out of annex one, developing country any more. It’s going to have to come into the fold and 

help to be a leader, together with India and other near-developed 

countries. Near-developed is at a level now that is compelling, with 

respect to the responsibility we all have to assume. 

My staff was just over at the meetings in Bangkok and I was in 

Bali, and under the terminology where we have to find common but 

differentiated responsibilities. It’s a critical issue the threading of 

this needle will depend on what life we give to the definition of differentiated, as well as common. The common we’ll be able to identify, the differentiated we’re going to have to struggle with a little 

bit. 

That’s why it’s critical. This hearing is important and it’s critical 

that we develop carbon capture and storage technology. As recommended last year in a seminal report by the Massachusetts Institute of Technology, that can enable us to capture emissions from 

power plants and other industrial facilities, and permanently bury 

them in deep saline aquifers and other geological formations. Two 

recent reports identified carbon capture and storage as the most 

promising area for emissions reductions in the electric power sector. 

3 

A December 2000 McKinsey study determined that by 2030, 9 

percent of electricity could come from coal plants equipped with 

CCS. The Electric Power Research Institute, which is testifying before the Committee today, estimated the number at 15 percent. 

These studies demonstrate the tremendous potential for the application of CCS. Our government ought to be making a significant 

commitment to advancing this technology. 

Nevertheless, in late January, the Department of Energy announced that it was cancelling FutureGen, the premier program for 

developing coal-fired power plants with CCS technology. The announcement brought an end to a program started 4 years ago and 

described, at that time, as ‘‘one of the boldest steps our Nation has 

taken toward a pollution-free energy future.’’ 

So today’s hearing will give us the opportunity to explore the reasons for the cancellation of the program, the implications of that 

decision, and how, if there are not serious implications, we’re going 

to make up for that, whatever they are, by accelerating the development and deployment of CCS technology in this country. 

Many of us in the Congress are working very hard to promote 

this. The energy bill that passed last summer was a start. It included key provisions to inventory the country’s sequestration capacity and conduct a Central Demonstration Project. Separately, 

I’ve introduced legislation with Senator Stevens, the Ranking 

Member of this Committee, called the Carbon Capture and Storage 

Technology Act of 2007, which would establish three to five commercial-scale sequestration facilities and three to five coal-fired 

demonstration plants with carbon capture. 

We’ve kept hearing from the industrial sector of our country, indeed from the private sector that the big gap is the lack of any 

commercial-scale enterprise. So we don’t know exactly what this is 

going to take, what the feasibility is, or what the cost is going to 

be in the end. 

It’s on this that we really want to focus today. We want to look 

to the testimony of this expert panel of witnesses and focus on the 

role of commercial-scale CCS projects, and the best way for us to 

advance the development and deployment of this essential technology. And, I very much look forward to exploring that with you, 

and I thank you all for taking the time to come here. 

Senator Ensign? 

STATEMENT OF HON. JOHN ENSIGN, 

U.S. SENATOR FROM NEVADA 

Senator ENSIGN. Thank you, Mr. Chairman. I think these hearings are very important hearings. We all know that the reserves 

of coal that we have in the United States will continue to be a big 

part of our energy supply. People have talked about nuclear, and 

we know that we don’t have a lot of nuclear expertise in this country today. Further, even if we wanted to build nuclear power 

plants, building them would take time, and we just don’t have the 

capacity to build very many of them. 

The electricity needs of this country are growing faster than can 

be met. I am a strong supporter of alternative technologies. I would 

ask consent, by the way, that my full statement be made part of 

the record. 

4 

[The prepared statement of Senator Ensign follows:] 

PREPARED STATEMENT OF HON. JOHN ENSIGN, U.S. SENATOR FROM NEVADA

Mr. Chairman, I would like to thank you for holding this hearing today on ‘‘Coal 

Gasification Technologies and the Need for Large Scale Projects.’’ 

It is widely recognized that continued reliance on Middle East oil is neither smart 

energy policy nor smart security policy. In order to meet the rapidly growing energy 

needs of this country, we must develop the resources that are available domestically. 

This cannot be done using only one fuel or one technology. It must be done by using 

all of the resources at our disposal, including coal. As an effort to break the partisan 

gridlock, I introduced a broadly bipartisan bill with Senator Cantwell last week to 

encourage the continued development of renewable energy. 

Coal is both abundant and inexpensive. In the United States alone, coal-fired 

power plants satisfy more than half of the Nation’s energy needs, and this percentage is likely to increase in the future. 

The key is to ensure that we are employing this resource in the most efficient and 

environmentally responsible manner possible. New technologies to make this possible are on the horizon. Carbon capture, sequestration, and IGCC technology are 

just a few of many processes already in development. Groundbreaking research is 

being conducted to develop ways to burn coal in order to maximize energy yield and 

employ cleaner and more efficient processes. 

As most of us are aware, the FutureGen project was designed to demonstrate the 

feasibility of these new technologies by constructing a state-of-the-art, zero-emissions power plant. In January of this year, the Department of Energy announced 

that it was restructuring the FutureGen program. It’s being restructured from a single demonstration project of integrated technologies to a new strategy of multiple 

commercial demonstration projects. While many consider this a setback, I believe 

that the idea of FutureGen can still be realized. 

Nevada is a prime example of a state dedicated to doing its part to meet our growing energy needs and has been a national leader in generating clean energy. Nevada 

is committed to keeping its energy supply diverse and is planning to advance stateof-the-art, environmentally compliant, clean-coal technologies at the Ely Energy 

Center. 

The Ely Energy Center is a 2,500 Megawatt complex that will incorporate the best 

available emission reduction technology today, yet provide flexibility for CO2 re- moval in the future. The first two coal units will use ultra super-critical pulverized 

coal technology. This process uses a boiler design that produces high temperatures 

and pressures to improve the energy conversion efficiency. This increased efficiency 

results in the use of less coal per kilowatt-hour produced, which means lower emissions. In addition to the ultra super-critical boilers, the Ely Energy Center is using 

a water-efficient hybrid cooling method, reducing water use by 50 percent. Finally, 

the plant will be constructed to be carbon capture ready by setting aside sufficient 

real estate within the plant layout to accommodate capture equipment, once it becomes technically feasible and commercially available. 

The remainder of the Ely Energy Center will be IGCC. The process of IntegratedGas-Combined-Cycle creates a gas out of the coal that may have properties that will 

make the CO2 capture easier. 

In Nevada, we believe that technological advancements in carbon capture and sequestration technologies are essential to our energy future. Sierra Pacific Resources, 

EPRI, and several other utilities are co-sponsoring an innovative project that demonstrates a new technology to separate and capture carbon dioxide emissions from 

a coal-fueled power plant in Wisconsin. This technology is being tested to see whether it can be scaled up to work on larger facilities. We hope the Ely Energy Center 

will become home to the 3rd generation of CCS demonstration projects as EPRI continues to test such technologies. 

While I believe it is vital to explore several energy sources in order to meet our 

growing energy needs, I also recognize that there will be times when the wind is 

not blowing and the sun is not shining. Coal will continue to provide the energy necessary to keep America going. We must develop the technology that allows us to utilize this abundant natural resource in a manner that is cleaner and friendlier to 

our environment. 

I look forward to hearing from the witnesses. 

Senator KERRY. Without objection, it will be. 

Senator ENSIGN. Currently, Senator Cantwell and I have an alternative energy bill on the floor of the Senate that will be voted 

5 

on later today. I strongly believe in alternative energies and believe 

that they need to be a big part of our future. 

The fact is, however, that you cannot build enough solar, enough 

geothermal, enough wind, etc. to offset our reliance on fossil fuels. 

Technologies may continue to develop in the future, but right now, 

with our current technologies, we certainly cannot come close to 

meeting the growth, let alone replacing the greenhouse gas-producing emission plants that we have today. 

I think it’s very important that we come together and discuss the 

concerns about our Nation’s energy security, on pumping a lot of 

money into countries that don’t necessarily like us, and combine 

those with economic concerns, and environmental concerns. 

In my state, to describe it simply, we have more renewable energy sources per capita than any other location in the country. The 

sun shines more than it does in any other state. We have several 

areas where we’ll be able to take advantage of the wind. In eastern 

and parts of northern Nevada we have some of the largest geothermal ‘‘reserves’’ in the United States. Northern Nevada, can be 

powered just with geothermal. 

These technologies, however, are so expensive by themselves that 

they cannot justify building the transmission lines. Currently, we 

are trying to build a coal-fired power plant in eastern Nevada. This 

plant would allow our state to be able to provide alternative, renewable technology throughout the State, and justify the cost of 

the transmission lines. 

This is just one example why a coal plant is still important. 

First, this will be a new coal plant. We will shut down two older 

coal plants that are a lot less efficient and a lot dirtier. This will 

bring more renewable energies that are good for the environment, 

onboard. 

One of the reasons I think it’s important for holding this hearing 

is, to discuss the FutureGen plant closure. There are different 

types of coal in different parts of the country, and there are different geological environments that we need to study. I am not 

sure that this isn’t the best strategy to find a few different sites 

to study the technology for not only capturing the carbon, but 

where to and how to sequester the carbon in an environmentally 

safe way. Further, I believe that we should study this, so that we 

can make this as commercially viable in the future as possible. 

I have talked to Secretary Bodman about the Ely Energy Center, 

which will be the coal-fired plant that I mentioned. It’s a 1,500- 

megawatt plant that could compete for one of these sites that the 

Department of Energy is talking about. Ely is a suitable site to test 

carbon capture and sequestration technologies. 

I think that there is a bright future if we continue to invest. This 

really is an investment in the future of America, the future of 

America’s energy needs, the future of America’s economy, and the 

future of America’s environment. All of these together must be examined. I think this is a very, very important hearing, and I hope 

that we can continue to discuss this topic in the future. 

Senator KERRY. Thank you very much, Senator Ensign. And I’m 

delighted to have you as a Ranking Member and as a partner in 

this effort. I think, it’s obviously bipartisan and we need just to 

6 

find the most common sense approaches. I’m delighted to work 

with you on it, as well as on many other things. I appreciate it. 

Dr. Marburger, thank you for coming up here again, you’re getting to be a regular, but we enjoy that, and we’re glad to have your 

expertise here today. 

Let me just run through everybody. We’ve got Dr. Marburger, the 

Director of Office of Science and Technology Policy, Executive Office of the President; Mr. James Childress, the Executive Director 

of Gasification Technologies Council; Dr. Joseph Strakey, Chief 

Technology Officer, U.S. Department of Energy, National Energy 

Technology Laboratory; Michael Mudd, the Chief Executive Officer 

of FutureGen Alliance; David Hawkins, Director of the Climate 

Center, Natural Resources Defense Council, and John Novak, Executive Director of Federal and Industry Activities for Environment 

and Generation, of the Electric Power Research Institute. Thank 

you all for being here. 

Dr. Marburger, would you lead off and we’ll just run right down 

the line. We look forward to a good discussion. 

Let me just remind everybody, I know you’ve all testified and 

you’re old pros at this, but all of your testimony will be placed in 

the record in full. If you can sort of, draw it into some kind of a 

summary in 5 minutes, that would be great. Thanks. 

STATEMENT OF HON. JOHN H. MARBURGER III, PH.D., 

DIRECTOR, OFFICE OF SCIENCE AND TECHNOLOGY POLICY, 

EXECUTIVE OFFICE OF THE PRESIDENT 

Dr. MARBURGER. Thank you, Chairman Kerry, and Ranking 

Member Ensign. I am pleased to be here to respond to your invitation to talk about the Administration’s technology initiatives to 

mitigate climate change. There’s a lot in my written testimony and 

I refer you to that for filling this out. You asked me to give an overview and I’ll just give a very brief summary in these oral remarks. 

It’s true that anthropogenic contributions to climate change are 

caused mostly by burning fossil fuels to produce energy, and coal 

is the cheapest, most abundant fossil fuel. Coal is a primary fuel 

for electrical power in China, which is annually adding power-generating capacity equal to that of the entire country of France. 

Coal and natural gas together account for about 70 percent of the 

world’s electric power production, and their emissions account for 

a similarly large percentage of greenhouse gas emissions. And most 

of the remainder comes from the use of petroleum, mainly for 

transportation. 

So, strategies for substantially reducing the human production of 

greenhouse gases ultimately become strategies for producing energy in a way that does not release CO2 into the atmosphere, and 

this is a problem of technology. 

As my written testimony makes clear, this is a very difficult 

problem because energy is the foundation of national economies, 

and there is a strong incentive to use the least expensive means 

for producing it. Some existing energy technologies produce zero 

net carbon emissions, but of these, only nuclear power can be 

scaled up to the magnitudes necessary to meet the vast energy 

needs of large economies. Wind and solar are intermittent sources 

that will require conventional stand-by power until new energy 

7 

storage technologies become available. Other sources, such as tidal 

or geothermal, can address only a fraction of the need. 

The progress of nuclear power is inhibited by thorny issues of nuclear proliferation and spent-fuel management. Biomass is an attractive energy source because it simply recycles carbon already in 

the atmosphere, rather than adding to it, but it, too, is difficult to 

scale up to the necessary magnitude, even with enhanced technologies for extracting energy from more of its substance. 

This overview suggests many opportunities for new or improved 

technologies, and a vigorous policy for addressing greenhouse gas 

emissions should address all of them. In no case, however, are existing technologies available at the necessary low price or scale— 

or large scale—to permit large-scale transitions to lower zero-carbon energy production in the near future. 

The alternatives to new zero-carbon sources of energy production 

are to use less energy in the first place, and to remove carbon produced by existing fossil fuel energy technologies. Energy conservation is important in any case and should be pursued, but it can 

only be part of the solution. In the transportation sector, low-carbon fuels can have a great impact. For stationary power plants, 

capturing the carbon during the production cycle and storing it underground seems to be feasible, but efficient large-scale carbon capture technology has not been proven and the stability of underground storage arrangements has not yet been confirmed. 

So this overview suggests a long list of technology opportunities 

that need to be pursued across the spectrum, from basic research 

to the development of new energy systems. And this Administration has launched initiatives for every item on the list. 

My written testimony gives more detail, but the titles of these 

initiatives are familiar to many. Freedom Car, for example, is a hydrogen fuel initiative. Advanced Energy Initiative, FutureGen, the 

20-in-10 Plan, the Coal Research Initiative, and so on. This country 

has a proud record of investing in technologies that can help us 

with these problems. 

These initiatives are funded largely through the Department of 

Energy, and the Department of Energy is the lead agency for the 

President’s Climate Change Technology Program announced in 

2001, and including a dozen participating agencies. Their strategic 

plan, which is located on the program’s website, which is included 

in my written testimony, contains much more detail. 

In view of the continuing importance of coal for the world’s energy supply, clean coal initiatives are particularly important, not 

only for the U.S., but also for many other large economies around 

the world, including the large Asian countries. The President has 

request three-quarters of a billion dollars for fossil fuel energy research development and demonstration in Fiscal Year 2009, focused almost exclusively on coal. 

Funding for the Coal Research Initiative, the CRI, has grown by 

87 percent over the past 3 years, and the research, development, 

and demonstration activities within this initiative are now almost 

entirely focused on carbon capture and storage technologies. The 

funding request for these technologies is more than triple the 2001 

amount. 

8 

1 Energy Information Administration, International Energy Outlook 2007, www.eia.doe.gov/ 

oiaf/ieo/emissions.html. 

The Coal Research Initiative, which includes the FutureGen Program and Clean Coal Power Initiative, seeks to reduce the cost and 

demonstrate the commercial feasibility of coal gasification and CCS 

technologies. The CRI funds a full range of R&D activity, including 

applied research, advanced technology development, pilot-scale 

testing, public and stakeholder outreach, and large-demonstrations 

in partnership with industry. Funding requested for this program 

is $588 million in the 2009 budget, up 20 percent—27 percent year 

to year—with the FutureGen program more than doubling to $156 

million. 

Specific activities under the CRI, include carbon sequestration 

research and demonstrations, as well as R&D on advanced turbines, advanced gasifiers, and other IGCC technologies, such as 

those for gas cleaning, conditioning and separation. 

This Administration is strongly committed to enabling cost-effective coal-based power generation, with near-zero atmospheric emissions. Coal gasification, and the associated carbon capture and sequestration technologies are an essential part of our global vision 

for a low-carbon future. 

Mr. Chairman, you have many experts on this panel, and I will 

defer technical questions to them, but we’re proud of the capabilities that have been brought to bear on this problem. 

Thank you. 

[The prepared statement of Dr. Marburger follows:] 

PREPARED STATEMENT OF HON. JOHN H. MARBURGER III, PH.D., DIRECTOR, OFFICE

OF SCIENCE AND TECHNOLOGY POLICY, EXECUTIVE OFFICE OF THE PRESIDENT

Chairman Kerry, Ranking Member Ensign, and Members of the Subcommittee, I 

am pleased to appear before you today to discuss ‘‘Coal Gasification Technologies 

and the Need for Large Scale Projects.’’ My remarks will focus on some contextual 

factors that make coal gasification technologies particularly relevant to our climate 

strategy. 

Fossil fuel energy production is the primary factor in the dramatic increase of atmospheric CO2 since the beginning of the industrial revolution. A basic understanding of the science of climate change would suggest that in the short run, we 

should seek to produce fewer greenhouse gases and increase absorption of those already in the atmosphere. In the long run, we should aim to limit releases to an 

amount much smaller than current values. And we should get on this path immediately, because Earth’s heat balance is already tilted and some effects of massive 

CO2 production are already evident. As you know, since 2001, the Administration 

has taken many actions to confront this challenge, and we are continuing to make 

progress both domestically and internationally. 

As we contemplate these actions, however, here are some numbers to keep in 

mind. The U.S. consumes more than 20 million barrels of oil per day, 60 billion 

cubic feet of natural gas per day, and 3 million tons of coal per day. This is about 

a fifth of the world’s energy consumption. World-wide, coal accounts for about 45 

percent of electricity production, natural gas about 24 percent, nuclear about 12 percent. Oil is used mainly for transportation and as a feedstock for the chemical industry. The current annual release from the world’s energy sector, by far the largest 

contributor to increased atmospheric CO2, is about 28 billion tons of CO2—40 percent from coal, 40 percent from oil, and most of the remaining 20 percent from natural gas.1

Suppose you wanted to reduce global emissions by just one billion tons—less than 

4 percent of the current global total. That would require building 136 new 1,000- 

MW nuclear plants (equivalent to one-third the existing world-wide nuclear capacity), or 150,000 2-MW wind turbines (about 3 times the current world capacity), or 

300 new coal gasification plants (500-MW each) with carbon capture and sequestraVerDate Nov 24 2008 13:10 May 24, 2012 Jkt 074322 PO 00000 Frm 00012 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\74322.TXT SCOM1 PsN: JACKIE
9 

2 Japan has proposed a global 2050 goal to reduce greenhouse gas emissions to 50 percent of 

current levels (i.e., reducing energy-related CO2 emissions to 14 billion tons-CO2 per year), while 

the EU has called for a 2050 goal of 50 percent of 1990 levels (i.e., reducing energy-related CO2

emissions to 10 billion tons-CO2 per year). Others have proposed even more aggressive goals. 

Many baseline, medium- to high-growth scenarios project global emissions in the range of 50 

to 70 billion tons-CO2 per year by 2050 (e.g., see the IPCC Special Report on Emissions Scenarios, http://www.grida.no/climate/ipcc/emission/005.htm). 3 AEO2008 Revised Early Release (available at http://www.eia.doe.gov/oiaf/aeo/excel/ 

aeotabl18.xls), which includes the expected emissions reductions resulting from the Energy 

Independence and Security Act of 2007. 4 In the EIA reference case, U.S. electricity consumption, including both purchases from electric power producers and on-site generation, grows from 3,814 billion kilowatt hours in 2006 to 

4,974 billion kilowatt hours in 2030, increasing at an average annual rate of 1.1 percent. In comparison, electricity consumption grew by annual rates of 7.3 percent, 4.2 percent, 2.6 percent, 

and 2.3 percent in the 1960s, 1970s, 1980s, and 1990s, respectively. [AEO2008 Revised Early 

Release] 5http://www.eia.doe.gov/oiaf/aeo/excel/aeotabl9.xls. 6http://www.eia.doe.gov/pub/international/iealf/tableh1co2.xls. 7http://www.eia.doe.gov/oiaf/ieo/emissions.html. 8http://www.eia.doe.gov/oiaf/aeo/excel/aeotabl18.xls. 9http://www.eia.doe.gov/oiaf/aeo/excel/aeotabl18.xls. 

tion (CCS), in place of conventional coal plants. Today, there are several carbon sequestration projects that each remove about 1 million tons of CO2 per year. This 

sounds like a lot, but is just one-thousandth of the billion we are looking for to 

achieve our 4 percent reduction. And international forums are talking about reductions on the order of 30 to 50 billion tons CO2 per year by 2050.2

These numbers are sobering. Fossil fuels have made modern economies and the 

incredible advances in standard of living over the last century possible. The economic development path has been paved with fossil fuels. For any given economy, 

CO2 production has been roughly proportional to Gross Domestic Product (GDP). 

The coefficient of proportionality is sensitive to technology; recently developed or developing economies are significantly more ‘‘carbon intensive’’ than older, developed 

economies. This is good news. It means that introducing modern energy technologies 

in the rapidly developing parts of the world can slow the growth of fossil CO2 relative to the historical development path. In fact, the objective of a CO2 mitigation 

strategy should be to eventually reduce the carbon intensity of the world’s economy 

toward zero, at the lowest possible socio-economic cost. 

A dramatic reduction in global energy emissions intensity will require deployment 

of advanced technology at a rate much higher than projected in baseline scenarios. 

The Energy Information Administration (EIA) projects that under current policies 

U.S. CO2 emissions from energy use will increase from 5.9 billion metric tons in 

2006 to 6.9 billion metric tons in 2030, an increase of 16 percent,3 primarily as a 

result of increased emissions from coal power plants and vehicle emissions. Total 

electricity consumption is expected to grow 30 percent over that time period—an average growth rate of 1.1 percent annually (which is much slower than the historical 

average, largely as a result of expected efficiency gains).4 In that timeframe, the 

EIA projects that about 100 gigawatts of new U.S. coal-fired generating capacity will 

be built (in addition to maintaining the existing capacity of 300 GW), including 30 

gigawatts of integrated gasification combined-cycle (IGCC) plants without CCS.5

From 2006 to 2030, new coal power plants are expected to increase power sector 

CO2 emissions by 700 million metric tons per year, representing about three-quarters of the net increase in U.S. emissions over that time period. 

Globally, the rate of emissions growth is expected to be much more rapid. In 2005, 

global energy-related CO2 emissions amounted to 28 billion metric tons, of which the 

United States’ emissions represented 21 percent.6 By 2030, global emissions are projected to total 43 billion metric tons.7 The EIA projects that the United States will 

account for about 16 percent of total global CO2 emissions in 2030, and about 7 percent of the growth in emissions from 2005 to 2030.8 By comparison, about 60 percent of the increase from 2005 levels is expected to come from China, India, and 

other non-OECD (Organization for Economic Cooperation and Development) Asian 

nations. U.S. coal-fired generation is projected to be 6 percent of global emissions 

in 2030,9 while globally, emissions from coal combustion in all forms will grow by 

two-thirds, amounting to 18 billion tons-CO2 per year (43 percent of total CO2 emissions) by 2030.6

The global trends of rapid emissions growth in developing nations and a dramatic 

expansion of coal-related emissions have been obvious for some time. As early as 

2001, it was clear that a major factor in climate policy had to be a realistic strategy 

for recruiting large developing economies into an international framework. It was 

equally clear that climate policy is strongly linked to energy policy, and that the 

10 

scale of the problem would require a campaign that would have to be maintained 

over the better part of a century. And it was clear that the already polarized nature 

of the public discourse was obscuring the scale and nature, not so much of the reality of anthropogenic climate change, but of the societal response that would be required. 

In 2002, the President set a target of cutting our greenhouse gas intensity by 18 

percent through the year 2012. When announced, this commitment was estimated 

to result in about 100 million metric tons of reduced carbon-equivalent emissions 

in 2012, with more than 500 million metric tons of reduced carbon-equivalent emissions in cumulative savings over the decade. Today, we are well ahead of the interim milestones to achieve that target. According to Environmental Protection 

Agency data reported to the United Nations Framework Convention on Climate 

Change (UNFCCC), U.S. greenhouse gas intensity declined by 2 percent in 2003, 2.5 

percent in 2004, 2.2 percent in 2005, and 4.2 percent in 2006—a 10.4 percent drop 

in those 4 years alone. 

Why shouldn’t the goal be simply to reduce the absolute carbon emissions toward 

zero? Why bring in the notion of ‘‘intensity’’? Because the cause of our climate anxiety in the first place—the root cause—is the overwhelming desire of people everywhere to improve their lot. That desire will not be denied. From all I have ever read 

or seen of human behavior, the will to better human circumstances must be accommodated in any social plan of action, and especially one designed to persist over decades, perhaps centuries. If we are to make any progress in mitigating anthropogenic 

climate change, it will be necessary to break the link between economic development 

and fossil fuel emissions. Economic development—i.e. growth in GDP—and simultaneous CO2 reduction implies reducing carbon intensity. This is a point of the utmost 

importance in crafting a successful global climate strategy. 

The link between GDP and fossil fuel CO2 emissions is technology. Technology 

choices in a society, especially pervasive ones like energy technology, are dictated 

by cost. So what are the prospects for reducing the cost of low-carbon-emission technologies to the point where they will replace high-emission technologies in rapidly 

developing economies? I phrase the question this way to emphasize that dictating 

limits on carbon emissions to such a country is a fruitless exercise unless alternative, low-emission technologies are commercially available and feasible at scale. 

And let us be clear that if we are serious about combating anthropogenic climate 

change, fossil-related carbon emissions must be reduced in all major economies. It 

is not enough for only the ‘‘old rich’’ economies of Europe and America and Japan 

to eliminate their emissions. All major economies must eventually adopt low- or 

zero-carbon energy technologies. This poses a vexing economic conundrum, because 

adjustments in energy technologies must occur during precisely that epoch in postCold War history—our epoch—when a major transformation in global patterns of 

trade, wealth, and economic power is also occurring. Any country that intervenes 

in its own economy to increase the price of low-cost, high-carbon-emitting energy in 

order to make higher-cost, lower-emitting technology more competitive, would likely 

put itself at a competitive disadvantage with countries that do not have similar policies, at least in the short term. And it is likely that there will always be dissimilar 

policies as long as significant differences in standards of living exist among economies around the world. 

The cost associated with altering the energy technology of a large economy is very 

large. Economists come to widely different conclusions about the cost, and frankly 

I do not know how to evaluate the different claims. What I do know is that today— 

as we speak—very few low-carbon technologies exist that can be expanded to the 

necessary scale in the near term. I can think of only one, nuclear fission, that is 

sufficiently mature and sufficiently scalable to be a serious contender with low-cost 

coal plants. In the short term, renewable energy technologies such as wind and solar 

may help slow emissions, but we do not have low-cost versions of the ancillary technologies of electrical storage and transmission that are needed to scale these up 

even to their current potential. Biomass looks promising for transportation fuel, but 

is not yet very effective in reducing CO2 emissions overall, and is not obviously scalable to the larger electrical power industry. Nuclear power is carbon-free, but the 

subject of such public concern, justified or not, that its substantial expansion will 

come only with concerted effort. 

Coal, natural gas, and petroleum will continue to be the primary energy feedstocks for decades to come. We have, however, very few full-scale demonstrations 

of the technologies for capturing the carbon emissions of fossil-fuel combustion. Coal 

is the fuel we have to worry about most, especially on the global scale. It is currently the cheapest, most ubiquitous source of energy for stationary power generation, and it releases the greatest amount of CO2 when burned. The U.S. has vast 

coal reserves and about half of its electricity is generated from this fuel. Meanwhile, 

11 

10 International Energy Agency R&D Statistics, http://www.iea.org/Textbase/stats/rd.asp. 

China already uses 2.5 times as much coal as does the United States, and is adding, 

on average, more than one large coal-fired power plant every 2 weeks. Other developing nations such as India and the transitional Eastern European nations are also 

expected to rely heavily on coal for their economic growth. Thus it is clear that development of low-cost, commercially feasible CCS technologies for coal plants is an 

essential component of any long-term strategy to address climate change. 

The Administration has committed enormous resources for the advancement of 

low-carbon coal technologies. The President’s 2009 budget, when combined with the 

private match, will result in over $1 billion of investment for research, development 

and demonstration of these technologies. This is just the most recent addition to the 

already existing $1.6 billion in tax credits and at least $8 billion in loan guarantees 

for advanced coal projects, industrial gasification activities at retrofitted and new 

facilities that incorporate carbon capture and sequestration, and advanced coal gasification facilities. 

The Department of Energy (DOE) recently restructured the FutureGen program 

in order to focus government resources on carbon capture and storage. The new 

FutureGen will include multiple facilities, as opposed to just one, generating power 

at a commercial scale. This revamped initiative is expected to double the amount 

of CO2 sequestered compared to original FutureGen concept that was announced in 

2003. 

The Administration has implemented a broad array of strategies—including partnerships, consumer information campaigns, incentives, and regulations—that are directed at developing and deploying cleaner, more efficient energy technologies, conservation, biological sequestration, geological sequestration and adaptation. The 

President’s 2009 budget includes $8.6 billion for climate-change-related activities 

and tax incentives—an increase of 9 percent from the enacted Fiscal Year 2008 

(FY08) level. Since 2001, we have spent almost $45 billion on climate science, technology development, tax incentives and international assistance. Funding for the 

U.S. Climate Change Technology Program (CCTP), a multi-agency R&D portfolio led 

by DOE, is $4.4 billion in the FY09 budget (3 percent higher than FY08 and 27 percent higher than in FY07). This represents a large increase since the CCTP program 

office was formally established at DOE: the CCTP portfolio in FY03 was about $2.5 

billion. Also, the President’s Advanced Energy Initiative (which includes the Coal 

Research Initiative, nuclear energy R&D, basic energy research, and energy efficiency and renewable energy R&D programs, all of which are within the CCTP portfolio) has increased 80 percent over 3 years, with $3.2 billion in the FY09 request 

(versus $1.8 billion in FY06). 

The Administration is implementing mandatory regulations that will reduce carbon emissions. After calling for a renewable fuel standard and a large increase in 

vehicle efficiency standards in his 2007 State of the Union Address, President Bush 

signed into law in December the Energy Independence and Security Act of 2007, 

which includes substantial, mid-term requirements for vehicle fuel efficiency (40 

percent improvement), renewable fuels (36 billion gallons annually by 2022), and efficiency of appliances, lighting systems, and government operations. The EIA estimates that this law will result in some of the largest emission cuts in our Nation’s 

history, between 3.9 and 4.9 cumulative billion tons of CO2 emissions reductions 

through 2030. 

Internationally, President Bush has launched a Major Economies Process (MEP) 

to reach agreement on key elements of a post-2012 energy security and climate 

change arrangement under the UNFCCC, including the identification of a long term 

global goal for emissions reductions. The MEP will also focus on key sectors to help 

accelerate the development of advanced energy technologies. Japan currently outspends every other country on energy R&D—more than $3.5 billion in 2006. The 

U.S. was second in that year with more than $3 billion. No other country comes 

close. All the EU25 nations together contribute about $2.7 billion.10 Most of Japan’s 

energy research is on nuclear power, while most of the U.S. budget is for non-nuclear energy technology. There is much to do. Other countries can and should do 

more. The Administration is pursuing global cooperation in many forums. The United 

States is working with other countries on a new international clean technology fund 

to help accelerate the use of cleaner, lower-carbon technologies and infrastructure. 

The United States and EU have jointly proposed in the Doha negotiations in the 

World Trade Organization to rapidly eliminate the tariff and non-tariff trade barriers that impede investment in clean technologies and services. The Administration 

has played a leadership role in the recent, legally-binding agreement with key developing countries to accelerate the phase-out of hydrochlorofluorocarbons under the 

12 

Montreal Protocol, which will reduce emissions of greenhouse gases by at least 3 billion metric tons over the coming decades. Other significant efforts include the AsiaPacific Partnership on Clean Development and Climate with China, India, Australia, South Korea, Canada, and Japan; joint efforts to combat deforestation, which 

accounts for roughly 20 percent of global greenhouse gas emissions; and international collaboration on monitoring and adaptation tools, such as the Global Earth 

Observation System of Systems, a 72-nation collaboration that can help communities plan and prepare for the effects of climate variability and change. 

In the domestic arena, many of the actions by this Administration with respect 

to climate change have been taken in the name of energy security. The two goals 

are not quite the same, the points of divergence being the increased domestic production of oil and the use of coal without carbon sequestration. That is why it is 

so important to invest in CCS technologies. For both climate change and energy security, technology development must focus on scalable sources—nuclear and coal, 

while maintaining progress in other areas such as renewable power and efficient 

end uses. Of course, there is no reason to delay picking the low-hanging fruit of lowcarbon technology. We can increase the efficiency of cars, and convert them first to 

run on biofuels and later on electricity or hydrogen. We can capture the energy of 

wind when it blows and sun when it shines, and later when we have better batteries 

we can use such transient sources more effectively. We can reduce the energy consumption of lighting, of buildings, of domestic machinery and appliances, and of industrial processes, with existing technology. None of these measures, however, addresses the very large share of emissions from stationary power sources that burn 

fossil fuels, and particularly coal. 

The above discussion suggests that reducing carbon emissions from coal power 

plants ought to be a high priority for federally funded R&D. Recognizing these realities, the President’s request for Fossil Energy research, development and demonstration in FY09 is $754 million, which is focused almost exclusively on coal. 

Funding for the Coal Research Initiative (CRI) has grown by 87 percent over the 

past 3 years, and the research, development, and demonstration activities within 

this Initiative are now almost entirely focused on CCS technologies. The $588 million for CRI in FY09 compares with $170 million when the President first took office 

in 2001, or more than 3 times as much spending. As a result of these efforts, in 

partnership with industry and with other nations, coal gasification technology could 

enable low-cost capture and storage of a significant portion of the projected global 

carbon emissions over the next fifty years. But there are some big hurdles to overcome. While the United States and other coal-producing nations appear to have an 

abundance of potential geologic storage capacity, the stunningly large fossil fuel consumption numbers I quoted earlier highlight the immense challenges inherent in 

building the CCS infrastructure. Any industrial scale process has potential environmental impacts, and there are few greater industrial scales than that of power generation. The sequestration industry would have to be of comparable scale. Another 

challenge is cost. DOE estimates that IGCC power plants with CCS, if successfully 

implemented using today’s technology, would generate electricity at a cost 40 to 70 

percent higher than conventional coal plants. Most of that incremental cost derives 

from the energy penalty in capturing CO2 from the gasified coal. Clearly, such excessive costs will inhibit the deployment of these technologies, especially on a global 

scale. Furthermore, the reliability of commercial-scale IGCC plants with CCS has 

not been suitably demonstrated. 

The Coal Research Initiative (CRI), which includes the FutureGen program and 

Clean Coal Power Initiative (CCPI), seeks to reduce the cost and demonstrate the 

commercial feasibility of coal gasification and CCS technologies. The CRI funds a 

full range of R&D activity, including applied research, advanced technology development, pilot-scale testing, public and stakeholder outreach, and large-scale demonstrations in partnership with industry. Funding for the CRI is $588 million in the 

FY09 budget (an increase of 27 percent, or $124 million, above FY08), with $156 

million for the FutureGen program (versus $74 million in FY08). Specific activities 

under the CRI include carbon sequestration research and demonstrations as well as 

R&D on advanced turbines, advanced gasifiers, and other IGCC technologies, such 

as those for gas cleaning, conditioning, and separation. Meanwhile, the recent refocusing of FutureGen will enhance its usefulness as a demonstration (actually, several demonstrations) of the commercial feasibility of these technologies. 

In summary, the Administration remains strongly committed to a goal of enabling 

cost-effective, coal-based power generation with near-zero atmospheric emissions. 

Coal gasification—and the associated carbon capture and sequestration technologies—are an essential part of our global vision for a low-carbon future. 

Thank you for the opportunity to speak with you today. I am prepared to answer 

any questions you have. 

13 

Senator KERRY. Thank you very much, Doctor. We’ll look forward 

to following up on that a bit. 

Mr. Childress? 

STATEMENT OF JAMES M. CHILDRESS, EXECUTIVE DIRECTOR, 

GASIFICATION TECHNOLOGIES COUNCIL 

Mr. CHILDRESS. Thank you, Mr. Chairman. 

The Gasification Technologies Council is composed of more than 

70 companies involved as plant owners, operators, technology suppliers, and equipment suppliers, and collectively account for about 

95 percent of world gasification capacity. 

I’d like to briefly summarize my written remarks, first addressing, what is gasification? It is a proven manufacturing process that 

converts carbon-containing materials into a synthesis gas, or a syngas, which is used to produce chemicals, plastics, fertilizer, fuels, 

and the subject of today’s hearing—electricity. 

It is not combustion—that’s an important differentiation when it 

comes to environmental performance, both in terms of air emissions and in terms of carbon capture and storage and, if necessary, 

we can get into that discussion later, it is in my written testimony. 

Gasification has been in commercial use for more than 50 years 

in the chemical and refining industry, and for more than 35 years 

in the power industry. Today there are more than 140 plants in operation around the world, with capacity expected to grow by another 70 percent by 2015, 80 percent of that growth will be in 

China. In the U.S., there are 19 operating gasification plants. 

Integrated Gasification Combined Cycle (IGCC) joins a modern 

gasification system with an efficient combined-cycle power plant, 

similar to that used for natural gas combined cycle generation, that 

provides the most efficient, cleanest way to produce electricity from 

coal. 

In my written statement, there is a chart that compares the air 

emissions of criteria pollutants for a coal-combustion plant, IGCC, 

natural gas and combined cycle plant. The differences are dramatic. IGCC is clearly cleaner, and it also has the potential to be 

the least-cost option for capturing and compressing CO2 in new 

coal-based power plants using currently available equipment and 

processes. That’s an important differentiation to note, because in 

combustion technologies, they’re very low on the learning curve on 

post-combustion CO2 removal. 

More than 90 percent of gasification capacity in the world already captures CO2. That is, chemical plants, fertilizer plants, 

those producing liquid and gaseous fuels, referred to as industrial 

gasification, already capture the CO2, but because there’s no economic or regulatory incentive, do not compress it for underground 

storage. They offer a lower-cost option for CO2 capture than do 

power plants. 

Because the manufacturing processes require the CO2 to be removed as part of the process, carbon capture in industrial gasification is part on the sticker price, if you will. It’s not an expensive 

option to add on, and a number of these plants are offering—in the 

United States—the option for near-term, large-scale carbon capture 

and storage at a lower cost than for power generation. 

14 

I just make reference to the Great Plains Substitute Natural Gas 

Plant in North Dakota where this is being done today. It’s not a 

power plant, it’s a chemical and natural gas plant. But it is capturing and selling the CO2 for enhanced oil recovery in Canada. 

Let me address the real reason for all of this, that’s coal, it’s 

what I call the ‘‘coal moratorium.’’ IGCC projects have not been immune to the political and regulatory roadblocks facing new coal 

combustion plants. A number of IGCC plants in development have 

been either indefinitely postponed, or cancelled, because of statelevel regulations, policies and programs, that require all new coalbased power generation to capture and store CO2, right out of the 

box. 

The net effect of this moratorium will be to increase demand for 

natural gas. As Senator Ensign pointed out, we do have a lot of alternatives—wind, solar, et cetera—but for base load power generation, the fuel of choice is going to be natural gas, and that is going 

to have an impact on price. 

I have a table in my written statement that indicates that certain analysts—and I think most analysts—are saying that between 

now and 2020, the demand for natural gas for power generation 

will rise by 45 percent—that is 3 quadrillion BTUs, or 3 trillion 

cubic feet of natural gas demand per year. 

We don’t have the reserves, we don’t have the production capacity. That’s going to raise the price. Second, we’re going to go to liquefied natural gas imports, that opens the U.S. market up to competing with higher-priced markets, basically Europe, Japan and 

Korea—so that the end result will be higher natural gas prices in 

the U.S. for industry. We’re already exporting jobs overseas in 

many of our natural gas-dependent industries, such as chemicals, 

fertilizers. Industries using natural gas for fuel, homeowners will 

also suffer. 

Industrial gasification offers one opportunity for rectifying this 

situation but even the industrial gasification facilities with lower 

CCS costs may, in fact, be faced with some of the same issues that 

have resulted from the coal moratorium. 

My recommendations are three-fold. First, we need financial support for demonstration at a commercial scale of multiple IGCCs, 

using different technologies, different coals, different geological situations so we can prove out, at a commercial scale, what we can 

do and what it’s going to cost with power generation and carbon 

capture and storage. 

We need, financial incentives for industrial gasification that recognize its unique ability for lower cost, nearer term capture and 

storage, and also offer some regulatory and liability protections for 

these first adopters. 

And finally, a uniform national policy on CO2. We need, whatever 

the preference is, whatever the flavor of the day is, we need a national program for CO2 capture, regulation, and very importantly, 

for the regulations involving storage. It gets to basic legal and liability issues, if we’re going to move forward with CCS, and power 

generation and gasification. 

Thank you. 

Senator KERRY. National standard for the reduction? 

Mr. CHILDRESS. Exactly. Yes, sir. 

15 

[The prepared statement of Mr. Childress follows:] 

PREPARED STATEMENT OF JAMES M. CHILDRESS, EXECUTIVE DIRECTOR, 

GASIFICATION TECHNOLOGIES COUNCIL

Mr. Chairman and members of the Subcommittee, my name is James Childress. 

I am the Executive Director of the Gasification Technologies Council (GTC). The 

GTC has more than seventy companies that own and operate plants, or provide the 

technologies, processes, services and equipment essential to their operation. Gasification plants in which our members are involved account for more than 95 percent 

of world capacity. 

In my testimony today I would like to address issues associated with gasification’s 

readiness to compress and capture CO2 and public policy steps that could be taken 

to accelerate commercialization of sequestration of CO2 from IGCC power plants and 

gasification-based manufacturing facilities. Also, with opposition to coal-based power 

plants threatening to put severe price and supply pressures on natural gas, gasification technologies can help the United States meet its energy needs in environmentally and economically sound ways. 

The Technology 

Gasification is a proven and efficient manufacturing process that converts hydrocarbons such as coal, wastes, or biomass into a clean synthesis gas (syngas), which 

can be used to produce chemicals, plastics, fertilizers, fuels, and electricity. Gasification is not a combustion process. 

Gasification has been used commercially on a global scale for more than 50 years 

by the chemical, refining, and fertilizer industries and for more than 35 years by 

the electric power industry. There are more than 420 gasifiers currently in use in 

some 140 facilities worldwide. Nineteen plants are operating in the United States. 

Growth in the Industry 

Worldwide gasification capacity is projected to grow 70 percent by 2015, with 

some 80 percent of the growth occurring in Asia. China is expected to achieve the 

most rapid growth as it moves aggressively to displace use of oil and gas in its 

chemicals and fertilizer industries. There are also seven coal-to-substitute natural 

gas projects in development in China. In addition, there are twelve proposed gasification-based IGCC power plants under evaluation by the Chinese government. 

Since 2004, 29 new gasification plants have been licensed and/or built in China. 

In contrast, no new gasification plants have started up in the United States since 

2002. In the U.S., plans have been announced for some 45–50 new gasificationbased projects in twenty-five states. However, whether these plants will actually be 

constructed depends on a number of factors, perhaps the most important of which 

is the lack of a clear regulatory framework addressing carbon capture and sequestration. 

Power Generation—IGCC 

An Integrated Gasification Combined Cycle (IGCC) power plant combines the gasification plant with a ‘‘combined cycle’’ power plant. Clean syngas is combusted in 

high efficiency gas turbines to produce electricity. The excess heat from the gasification reaction is captured, converted into steam and sent to a steam turbine to 

produce additional electricity. IGCC offers both significant environmental benefits 

and the lowest-option for carbon capture of any coal-based power generation method. 

Compared to traditional combustion-based technologies producing electricity from 

coal, an IGCC shows marked reductions in all criteria air pollutants, higher efficiency, and lower water use and solid waste generation. Air emissions from an IGCC 

approach those of a natural gas combined cycle (NGCC) plant. (Source: IL DEP, GE 

Energy) 

16 

Commercial technology exists today to remove more than 95 percent of the mercury from a gasification-based plant at one-tenth the cost of removal for a coal combustion plant. 

Carbon Capture 

More than 80 percent of global gasification capacity is already capturing CO2. 

What are commonly called ‘‘industrial gasification’’ facilities, chemical, plastics, fertilizer, fuels and hydrogen plants routinely capture the CO2 as part of their manufacturing process. However, because of lack of economic incentives or regulatory requirements, the CO2 is not sequestered. 

Gasification also provides the least cost path toward capturing CO2 emissions associated with power generation from coal, heavy petroleum residues such as petcoke 

and other fossil fuels. This is because the syngas being treated in an IGCC power 

plant is under pressure and is approximately 1 percent of the volume of post-combustion exhaust gas that must be cleansed in a conventional coal-fired plant. This 

results in lower capital and operating costs for the IGCC as well as reduced parasitic energy requirements. Costs of carbon capture and pressurization for industrial 

gasification facilities are even lower, because the equipment and processes necessary 

for removing CO2 from the gas stream are part of the manufacturing process. 

(Source: Eastman Chemical, MIT) 


409child1.eps
17 

Consequences of a Moratorium on Coal-based Power Generation, Including 

IGCC 

Despite the strong environmental benefits of IGCC, coal-based IGCC plants are 

facing the same opposition and delay encountered by combustion-based plants. 

Much of this is due to demands that IGCC plants incorporate carbon capture and 

sequestration in their initial operations. 

A prime example occurred in Florida last year when the Tampa Electric Polk Unit 

6 IGCC was indefinitely postponed when the state announced greenhouse gas reductions goals, but without the necessary regulatory structure and certainty to implement those reductions. The Tampa utility has been successfully running its first 

IGCC at the Polk plant since the mid-1990s and expectations were that the new 

unit would provide valuable experience leading to increased investor and owner confidence in IGCC technology. 

Since the postponement, Tampa Electric has announced that the additional capacity the new IGCC would have provided will now be met by natural gas powered generation. This scenario is typical of coal cancellations in the U.S. Despite calls for 

efficiency and renewables as alternatives to coal, the power generation fuel of choice 

is natural gas. This demand for natural gas-based power generation is accelerating 

because of its low emissions and higher capacity factor. 

The Energy Information Administration estimates that by 2020 the use of coal for 

power will increase while the use of natural gas will decline. (Source: U.S. EIA) 

U.S. Fuel Demand for Power Generation (Quads) 

2007 2020 

Coal 20.68 23.67 

Natural Gas 6.77 5.92 

Renewables 3.65 5.64 

The EIA forecast is clearly unrealistic—coal use will not rise under the current 

circumstances and gas certainly will not decline. Industry analysts have indicated 

that incremental natural gas demand of 3 quads will be needed to meet the expected 

coal shortfall, even while U.S. natural gas production has been essentially flat. 

One analysis of the consequences of a de facto coal plant moratorium lays out the 

following scenario: 

• Incremental natural gas demand will have to come from marginal gas supplies. 


409child2.eps
18 

• North American gas fields look to be maxed out at current demand levels. 

• Marginal supplies will probably need to be purchased from the global liquefied 

natural gas (LNG) market. 

• Therefore, U.S. gas prices will be determined by much higher European and 

Asian prices, will be oil indexed to attract spot cargoes. 

The price impacts of this rise in natural gas demand for power generation will 

be severe for industries such as chemicals, plastics and fertilizers that rely on natural gas as a feedstock, manufacturers that use gas as a fuel, and homeowners, already faced with skyrocketing oil and gasoline prices. 

Industrial gasification offers one element of a solution—through plants gasifying 

coal or petroleum coke to produce chemicals, fertilizers or substitute natural gas 

(SNG), but the public policy and political climate is not reassuring. We propose the 

outline of a way forward. 

Conclusions and Recommendations 

There is the need for a sustained, long term carbon capture and sequestration initiative involving government and industry. The initiative should provide assurances 

to industry, the investment community and regulators that CCS via gasification is 

a viable option for capturing and sequestering CO2 emissions from power generation 

and manufacturing. The elements of the initiative should include: 

• Demonstration at a commercial scale of multiple IGCC power plants with CCS 

using a variety of coals; 

• Incentives that recognize and reward the ability of industrial gasification to 

offer large scale, near term opportunities for CCS at lower costs; and 

• A uniform national policy framework addressing regulation of CO2 emissions 

and CCS, including incentives and liability indemnification for early adopters. 

Thank you. I will be happy to answer any questions you may have. 

APPENDIX

GASIFICATION TECHNOLOGIES COUNCIL

Gasification: Background Information 

What is Gasification? 

Gasification is a manufacturing process that converts carbon-containing materials, 

such as coal, petroleum coke (‘‘petcoke’’), biomass, or various wastes to a ‘‘synthesis 

gas’’ or ‘‘syngas’’ which can then be used to produce valuable products, such as, electric power, chemicals, fertilizers, substitute natural gas, hydrogen, steam, and transportation fuels. 

Gasification Is Not Combustion 

Gasification is a partial oxidation (reaction) process which produces syngas comprised primarily of hydrogen (H2) and carbon monoxide (CO). It is not a complete 

oxidation (combustion) process, which produces primarily thermal energy (heat) and 

residual solid waste (slag), criteria air pollutants (NOX and SO2), and carbon dioxide 

(CO2). 

How Does Gasification Work? 

Feedstocks 

Gasification enables the capture—in an environmentally beneficial manner—of 

the remaining ‘‘value’’ present in a variety of low-grade hydrocarbon materials 

(‘‘feedstocks’’) that would otherwise have minimal or even negative economic value. 

Gasifiers can be designed to run on a single material or a blend of feedstocks: 

• Solids: All types of coal and petroleum coke (a low value byproduct of refining) 

and biomass, such as wood waste, agricultural waste, and household waste. 

• Liquids: Liquid refinery residuals (including asphalts, bitumen, and other oil 

sands residues) and liquid wastes from chemical plants and refineries. 

• Gas: Natural gas or refinery/chemical off-gas. 

Gasifier 

The core of the gasification system is the gasifier, a pressurized vessel where the 

feed material contacts with oxygen (or air) and steam at high temperatures. There 

are several basic gasifier designs, distinguished by the use of wet or dry feed, the 

use of air or oxygen, the reactor’s flow direction (up-flow, down-flow, or circulating), 

19 

and the gas cooling process. Currently, gasifiers are capable of handling up to 3,000 

tons/day of feedstock throughput and this will increase in the near future. 

After being ground into very small particles—or fed directly (if a gas or liquid)— 

the feedstock is injected into the gasifier along with a controlled amount of air or 

oxygen and steam. Temperatures in a gasifier range from 1,400–2,800 degrees Fahrenheit. The heat and pressure inside the gasifier break apart the chemical bonds 

of the feedstock forming syngas. 

The syngas consists primarily of hydrogen and carbon monoxide and, depending 

upon the specific gasification technology, smaller quantities of methane, carbon dioxide, hydrogen sulfide, and water vapor. Syngas can be combusted to produce electric power and steam or used as a building block for a variety of chemicals and 

fuels. Syngas generally has a heating value of 250–300 Btu/scf, compared to natural 

gas at approximately 1,000 BTU/scf. 

Typically, 70 to 85 percent of the carbon in the feedstock is converted into the 

syngas. The ratio of carbon monoxide to hydrogen depends in part upon the hydrogen and carbon content of the feedstock and the type of gasifier used. 

Oxygen Plant 

Most gasification systems use almost pure oxygen (as opposed to air) to help facilitate the reaction in the gasifier. This oxygen (95 to 99 percent purity) is generated 

by using proven cryogenic technology. The oxygen is then fed into the gasifier 

through separate co-feed ports in the feed injector. 

Gas Clean-Up 

The raw syngas produced in the gasifier contains trace levels of impurities that 

must be removed prior to its ultimate use. After the gas is cooled, the trace minerals, particulates, sulfur, mercury, and unconverted carbon are removed to very low 

levels using commercially-proven cleaning processes common to the chemical and refining industries. 

Carbon Dioxide 

Carbon dioxide (CO2) can also be removed at the gas cleanup stage using a number of commercial technologies. In fact, CO2 is routinely removed with a commercially proven technology in ammonia and hydrogen manufacturing plants. Ammonia 

plants already capture roughly equivalent to 90 percent of the CO2 and methanol 

plants capture approximately 70 percent. 

Byproducts 

Most solid and liquid feed gasifiers produce a glassy-like byproduct, which is nonhazardous and can be used in roadbed construction or in roofing materials. Also, in 

most gasification plants, more than 99 percent of the sulfur is removed and recovered either as elemental sulfur or sulfuric acid. Finally, for feeds (such as coal) containing mercury, more than 95 percent of the mercury can be removed from the 

syngas using relatively small and commercially available activated carbon beds. 

Which Industries Use Gasification? 

Gasification has been used in the chemical, refining, and fertilizer industries for 

more than 50 years and by the electric power industry for more than 35 years. Currently, there are more than 140 gasification plants—with more than 420 gasifiers— 

operating worldwide. Nineteen of those gasification plants are located in the United 

States. 

The use of gasification is expanding. For example, there are several gasification 

projects under development to provide steam and hydrogen for synthetic crude upgrading in the oil sands industry in Canada. In addition, the paper industry is exploring how gasification can be used to make their operations more efficient and reduce waste streams. 

Gasification Applications and Products 

Hydrogen and carbon monoxide, the major components of syngas, are the basic 

building blocks of a number of other products, such as chemicals and fertilizers. In 

addition, a gasification plant can be designed to produce more than one product at 

a time (co-production or ‘‘polygeneration’’), such as the production of electricity, 

steam, and chemicals (e.g., methanol or ammonia). This polygeneration flexibility allows a facility to increase its efficiency and improve the economics of its operations. 

Chemicals and Fertilizers 

Modem gasification has been used in the chemical industry since the 1950s. Typically, the chemical industry uses gasification to produce methanol as well as chemicals—such as ammonia and urea—which form the foundation of nitrogen-based fertilizers. The majority of the operating gasification plants worldwide are designed to 

20 

produce chemicals and fertilizers. And, as natural gas and oil prices continue to increase, the chemical industry is developing additional coal gasification plants to generate these basic chemical building blocks. 

Eastman Chemical Company helped advance the use of coal gasification technology for chemicals production. Eastman’s coal-to-chemicals plant in Kingsport, 

Tennessee, converts Appalachian coals to methanol and acetyl chemicals. The plant 

began operating in 1983 and has gasified approximately 10 million tons of coal with 

a 98 to 99 percent on-stream availability rate. 

Hydrogen for Oil Refining 

Hydrogen, one of the two major components of syngas, is used to strip impurities 

from gasoline, diesel fuel, and jet fuel, thereby producing the clean fuels required 

by state and Federal clean air regulations. Hydrogen is also used to upgrade heavy 

crude oil. Historically, refineries have utilized natural gas to produce this hydrogen. 

Now, with the increasing price of natural gas, refineries are looking to alternative 

feedstocks to produce the needed hydrogen. Refineries can gasify low value residuals, such as petroleum coke, asphalts, tars, and some oily wastes from the refining 

process to generate both the required hydrogen and the power and steam needed 

to run the refinery. 

Transportation Fuels 

Gasification is the foundation for converting coal and other solid fuels and natural 

gas into transportation fuels, such as gasoline, ultra-clean diesel fuel, jet fuel, naphtha, and synthetic oils. Two basic paths are employed in converting coal to motor 

fuels via gasification. In the first, the syngas undergoes an additional process, the 

Fischer-Tropsch (FT) reaction, to convert it to a liquid petroleum product. The FT 

process, with coal as a feedstock, was invented in the 1920s, used by Germany during World War II, and has been utilized in South Africa for decades. Today, it is 

also used in Malaysia and the Middle East with natural gas as the feedstock. 

In the second process, so-called Methanol to Gasoline (MTG), the syngas is first 

converted to methanol (a commercially used process) and the methanol is converted 

to gasoline by reacting it over a bed of catalysts. A commercial MTG plant successfully operated in the 1980s and early 1990s in New Zealand and one is under development in China. 

Transportation Fuels From Oil Sands 

The ‘‘oil sands’’ in Alberta, Canada are estimated to contain as much recoverable 

oil (in the form of bitumen) as the vast oil fields in Saudi Arabia. However, to convert this raw material to saleable products requires mining the oil sands and refining the resulting bitumen to transportation fuels. The mining process involves massive amounts of steam to separate the bitumen from the sands and the refining 

process demands large quantities of hydrogen to upgrade the ‘‘crude oil’’ to finished 

products. (Wastes from the upgrading process include petcoke, deasphalted bottoms, 

vacuum residuals, and asphalt/asphaltenes—all of which contain unused energy.) 

Traditionally, oil sand operators have utilized natural gas to produce the steam 

and hydrogen needed for the mining, upgrading, and refining processes. However, 

a number of operators will soon gasify petcoke to supply the necessary steam and 

hydrogen. Not only will gasification displace expensive natural gas as a feedstock, 

it will enable the extraction of useable energy from what is otherwise a waste product (the petcoke). In addition, black water from the mining and refining processes 

can be recycled to the gasifiers using a wet feed system, reducing fresh water usage 

and waste water management costs. (This is not inconsequential since traditional 

oil sand operations consume large volumes of water.) 

Substitute Natural Gas 

Gasification can also be used to create substitute natural gas (SNG) from coal. 

Using a ‘‘methanation’’ reaction, the coal-based syngas—chiefly carbon monoxide 

(CO) and hydrogen (H2)—can be profitably converted to methane (CH4). Nearly 

chemically identical to conventional natural gas, the resulting SNG can be used to 

generate electricity, produce chemicals/fertilizers, or heat homes and businesses. 

SNG will enhance domestic fuel security by displacing imported natural gas that is 

likely to be supplied in the form of Liquefied Natural Gas (LNG). 

Power Generation With Gasification 

As stated above, coal can be used as a feedstock to produce electricity from gasification. This particular coal-to-power technology allows the continued use of coal 

without the high level of air emissions associated with conventional coal-burning 

technologies. This occurs because in gasification power plants the pollutants in the 

syngas are removed before the syngas is combusted in the turbines. In contrast, conVerDate Nov 24 2008 13:10 May 24, 2012 Jkt 074322 PO 00000 Frm 00024 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\74322.TXT SCOM1 PsN: JACKIE
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ventional coal combustion technologies capture the pollutants after the exhaust gas 

has passed through the boiler or steam generator—generally using an expensive 

‘‘bag house’’ and/or ‘‘scrubber.’’ 

IGCC Power Plants 

An Integrated Gasification Combined Cycle (IGCC) power plant combines the gasification block with a ‘‘combined cycle’’ power block (consisting of one or more gas 

turbines and a steam turbine). Clean syngas is combusted in high efficiency gas turbines to produce electricity. The excess heat from the gasification reaction is then 

captured, converted into steam and sent to a steam turbine to produce additional 

electricity. The gas turbines can be operated on a backup fuel such as natural gas 

during periods of scheduled gasifier maintenance or can co-fire the backup fuel to 

compensate for any shortfall in syngas production. 

Gas Turbines 

In IGCC—where power generation is the focus—the clean syngas is combusted 

(burned) in high efficiency gas turbines to generate electricity with very low emissions. The turbines used in these plants are derivatives of proven, natural gas combined-cycle turbines that have been specially adapted for use with syngas. For IGCC 

plants that include carbon capture, the gas turbines must be able to operate on 

syngas with higher levels of hydrogen. Although modern state-of-the-art gas turbines are commercially ready for this ‘‘higher hydrogen’’ syngas, work is on-going 

in the United States to develop the next generation of even more efficient gas turbines ready for carbon capture-based IGCC. 

Heat Recovery Steam Generator 

Hot gas from each gas turbine in an IGCC plant will ‘‘exhaust’’ into a heat recovery steam generator (HRSG). The HRSG captures heat in the hot exhaust from the 

gas turbines and uses it to generate additional steam that is used to make more 

power in the steam turbine portion of the combined-cycle unit. 

Steam Turbines 

In most IGCC plant designs, steam recovered from the gasification process is 

superheated in the HRSG to increase overall efficiency output of the steam turbines, 

hence the name Integrated Gasification Combined Cycle. This IGCC combination, 

which includes a gasification plant, two types of turbine generators (gas and steam), 

and the HRSG is clean and efficient—producing NOx levels less than 0.06 lb per 

MMBtu (coal input basis) and combined cycle efficiencies exceeding 65 percent when 

process stream integrated from the gasification plant is included. 

Another example of the ‘‘integrated’’ design in the fully integrated IGCC is the 

IGCC gas turbine that can provide a portion of the compressed air to the oxygen 

plant. This reduces the capital cost of the compressors while also decreasing the 

amount of power required to operate the oxygen plant. Additionally, gas turbines 

use nitrogen from the oxygen plant to reduce combustion NOX as well as increase 

power output. 

Existing IGCC Power Plants 

Fourteen gasification based power plants are operating around the world with one 

more under construction. Total capacity for these fifteen plants is 4.1 gigawatts of 

electricity. Numerous additional projects are planned. 

In the U.S. two coal-based IGCC’s have been in operation for more than a decade. 

The 262 MW Wabash River Coal Gasification Repowering Project (Wabash) in Indiana began commercial operation in November 1995 and helped pioneer the use of 

coal gasification for power in the United States. Since 1995, this facility has gasified 

over 1.7 million tons of bituminous coal and over 2.0 million tons of petcoke. 

Tampa Electric Company also helped pioneer the use of coal gasification technology for power generation in the United States. Tampa’s 250 MW Polk Power Station near Lakeland, Florida, began operating in 1996 and serves 75,000 households. 

The Polk plant uses high sulfur Illinois and other coals, but also blends Power River 

Basin coal and petcoke in order to reduce fuel costs. The Polk Power station markets the slag from the gasifier for use in manufacturing roofing and concrete blocks. 

Sulfuric acid, another byproduct, goes into fertilizer production. 

What are the Environmental Benefits of Gasification? 

Besides fuel and product flexibility, gasification-based systems offer significant environmental advantages over competing technologies, particularly coal-to-electricity 

combustion systems. This advantage occurs because the net volume of syngas being 

treated pre-combustion in an IGCC power plant is 1⁄100 (or less) than the volume 

22 

of post-combustion exhaust gas that must be cleansed in a conventional coal-fired 

plant. 

Air Emissions 

Gasification can achieve greater air emission reductions at lower cost than other 

technologies, such as supercritical pulverized coal. In fact, coal IGCC offers the lowest emissions of sulfur dioxide (SOX) nitrogen oxides (NOX) and particulate matter 

(PM) of any coal-based power production technology. In addition, mercury emissions 

can be removed from an IGCC plant at one-tenth the cost of removal for a coal combustion plant. Technology exists today to remove more than 95 percent of the mercury from a gasification based plant. 

Solids Generation 

During gasification, virtually all of the carbon in the feedstock is converted to 

syngas. The mineral material in the feedstock separates from the gaseous products, 

and the ash and other inert materials fall to the bottom of the gasifier as a nonleachable, glass-like solid or other marketable material. This material can be used 

for many construction and building applications. In addition, more than 99 percent 

of the sulfur can be removed using commercially proven technologies and converted 

into marketable elemental sulfur or sulfuric acid. (See chart). 

Water Usage 

Gasification uses approximately 14 to 24 percent less water to produce electric 

power from coal compared to other coal-based technologies and water losses during 

operation are about 32 to 36 percent less than other coal-based technologies. This 

is a major issue in many countries—such as the United States—where water supplies have already reached critical levels. 

Sustainability 

Gasification can help move industrial and electric power facilities toward sustainability. It can reduce the environmental footprint from low-value waste materials by 

utilizing them as feedstock; rather than disposing of them. By extracting the useable energy from materials that would otherwise be treated as a waste and enabling 

reuse of waste waters, a facility can both reduce its environmental footprint and improve its operating margins. 

Carbon Dioxide 

In a gasification system, CO2 can be captured using commercially available capture technologies before it would otherwise be vented to the atmosphere. One commercially available removal technology that is used as part of carbon capture, called 

the water-gas shift reaction, is illustrated below: 

Converting the CO to CO2 prior to combustion is much simpler and more economical than doing so after combustion, effectively ‘‘de-carbonizing,’’ or at least reducing 

the carbon in the syngas. 

Plants manufacturing ammonia, hydrogen, fuels, or chemical products with a gasification system routinely capture CO2 as part of the manufacturing process. The 

Dakota Gasification plant in Beulah, North Dakota, captures the CO, while making 

substitute natural gas. Since 2000, this plant has sent captured CO2 via pipeline 

to EnCana’s Weyburn oil fields in Saskatchewan, Canada, where it is used for enhanced oil recovery. To date, more than five million tons of CO2 has been sequestered. 

According to the Environmental Protection Agency the higher thermodynamic efficiency of the IGCC cycle minimizes CO2 emissions relative to other technologies. 

IGCC plants offer today’s least-cost alternative for capturing CO2 from a coal-based 

power plant. In addition, IGCC will experience less of an energy penalty that other 

technologies if carbon capture is added. While CO2 capture and sequestration will 

increase the cost of all forms of power generation, the U.S. Department of Energy 

estimates that the cost of CO2 capture for a power plant concluded that the CO2

capture cost is 10 percent more expensive for a conventional coal plant as for an 

IGCC power generation facility. 

What are the Economic Benefits of Gasification? 

Gasification can compete effectively in high-price energy environments. While a 

gasification plant is capital intensive (like any manufacturing unit), its operating 

costs are potentially lower than many other manufacturing processes or coal combustion plants because a gasification plant can use low-cost feedstocks, such as 

petcoke. Due to continued research and development efforts the cost of these units 

will continue to decrease. 

23 

There are a number of significant economic benefits with gasification. Inherent in 

the technology is its ability to convert low-value feedstocks to high-value products, 

thereby increasing the use of available energy in the feedstocks while reducing disposal costs. The ability to produce a number of high-value products at the same time 

(polygeneration) helps a facility offset its capital and operating costs. In addition, 

the principal gasification byproducts (sulfur and slag) are readily marketable. 

Gasification offers wide fuel flexibility. A gasification plant can vary the mix of 

the solid feedstocks or run on natural gas or liquid feedstocks when desirable. This 

technology enables an industrial facility to replace its high-priced natural gas feed 

with lower priced feedstocks, such as coal or petcoke—thus reducing its operating 

costs. 

For example, a refinery using gasification to manufacture hydrogen and steam 

can replace its natural gas feedstock with waste materials that may otherwise have 

to be disposed of (such as petcoke). The ability to use lower value fuels enables a 

refinery to reduce both its fuel and disposal costs while producing the large quantities of hydrogen that are needed for cleaner transportation fuels. 

In addition, gasification units require less pollution control equipment because 

they generate fewer emissions; further reducing the plant’s operating costs. 

What is the Gasification Market Outlook? 

Worldwide gasification capacity is projected to grow 70 percent by 2015, with 81 

percent of the growth occurring in Asia. The prime movers behind this expected 

growth are the chemical, fertilizer, and coal-to-liquids industries in China, oil sands 

in Canada, polygeneration (hydrogen and power or chemicals) in the United States, 

and refining in Europe. China is expected to achieve the most rapid growth in gasification worldwide. There are seven coal-to-substitute natural gas gasification 

plants under development and twelve proposed IGCC plants in China. Since 2004, 

29 new gasification plants have been licensed and/or built in China. In contrast, no 

new gasification plants have started up in the United States since 2002. 

The gasification industry in the United States faces a number of challenges, including, rising construction costs and uncertainty about policy incentives and regulations. Despite these challenges, gasification is expected to grow significantly in 

this country. 

A number of factors will contribute to a growing interest in gasification, including 

volatile oil and natural gas prices, more stringent environmental regulations, and 

a growing consensus that CO2 management should be required in power generation 

and energy production. All of these factors contribute to a growing interest in gasification worldwide. 

Energy Security 

America is at a critical juncture in meeting its electric generating needs. Natural 

gas prices are volatile and while new natural gas supplies are being developed, 

those supplies are generally located outside the country. In addition, there is increasing concern about the need to diversify U.S. fuel requirements. Gasification is 

a technology that can help address some of these energy security concerns. Gasification can generate electricity and produce substitute natural gas and transportation fuels using major domestic resources such as coal or petroleum coke, thus reducing U.S. dependence on both foreign oil and foreign natural gas. 

Bioprocessing 

In addition to using the traditional feedstocks of coal and petroleum coke, gasifiers can utilize biomass, such as yard and crop waste, ‘‘energy crops’’, (such as 

switch grass), and waste and residual pulp/paper plant materials as feed. Municipalities as well as the paper and agricultural industries are looking for ways to reduce the disposal costs associated with these wastes and for technologies to produce 

electricity and other valuable products from these waste materials. While still in its 

infancy, biomass gasification shows a great deal of promise. 

A Link to the Future 

Gasification is a ‘‘link’’ technology to a hydrogen economy. Because gasification 

converts feedstocks such as coal directly into hydrogen, it can become a competitive 

route to producing the large quantifies of hydrogen that will be needed for fuel cells 

and cleaner fuels. By contrast, other technologies must first create the electricity 

needed to separate the hydrogen from water using electricity or expensive natural 

gas. 

Conclusions and Recommendations 

Gasification is the cleanest, most flexible way of using fossil fuels. Currently, over 

80 percent of the installed worldwide gasification capacity is capturing CO2. GasifiVerDate Nov 24 2008 13:10 May 24, 2012 Jkt 074322 PO 00000 Frm 00027 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\74322.TXT SCOM1 PsN: JACKIE
24 

cation also provides the lowest cost option for capturing CO2 from a fossil-fuel based 

power plant. 

While there are strong advantages to gasification, it also faces a number of challenges, particularly for coal-to-power applications. The following are needed to help 

with the widespread deployment of this technology: 

• Demonstration on a commercial scale of multiple IGCC power plants with CCS; 

• Policies that recognize and reward the ability of industrial gasification’’ (involved in the manufacture of products and fuels) to offer large scale, near term 

opportunities for CCS at lower costs; and 

• A uniform national policy framework addressing carbon dioxide including incentives and liability indemnification for early adopters. 

Senator KERRY. Thank you very much. 

Dr. Strakey? 

STATEMENT OF DR. JOSEPH P. STRAKEY, JR., CHIEF 

TECHNOLOGY OFFICER, U.S. DEPARTMENT OF ENERGY, 

NATIONAL ENERGY TECHNOLOGY LABORATORY 

Dr. STRAKEY. Thank you, Mr. Chairman, Senator Ensign, for inviting me to testify on DOE’s coal gasification program. 

My written testimony provides additional background on coal 

gasification, and to summarize it, it’s highly flexible—gasification 

can use a wide variety of feedstocks, and it can also produce multiple products, including fuels. Pollutants can be reduced down to 

almost any desired level, and CO2 can be easily concentrated and 

captured. I think we’re truly approaching zero-emission coal technology. 

Senator KERRY. Can you—you mind pulling the mike a little closer? 

Mr. STRAKEY. Sorry. 

Senator KERRY. And could you just repeat the last sentence 

again? 

Mr. STRAKEY. I think we are truly approaching zero-emission 

coal technology. 

We are aggressively pursuing other options, as well, namely oxycombustion, and post-combustion capture of CO2. We don’t expect 

to see a single winner, but we do believe that coal gasification will 

play a major role in our energy future. 

However, there are significant challenges that lie ahead, and 

that’s what I’d like to talk about today. 

Commercial experience with coal gasification in the United 

States is somewhat limited. There are only 6 gasification plants, 

and three of those are operating in Integrated Gasification Combined Cycle mode, to produce power. 

There is virtually no experience where IGCC has been integrated 

with carbon capture and storage. And that’s really one of the major 

goals of the FutureGen program. We think that without that demonstration, it’s highly doubtful that any future plants would be able 

to be financed. 

I also think that two such demonstrations would be a lot better 

and more convincing than one, and three would be better than two. 

Reliability is always a key concern, especially when new technologies are introduced. We need additional demonstrations in the 

clean coal technology program, to test the technologies that are in 

the pipeline, and convince bankers that their investment risks are 

acceptable. 

25 

Our regional carbon sequestration partnerships are making great 

strides in advancing our knowledge of the geologic storage of carbon dioxide and about its permanence and safety. The third phase 

of this program is just beginning, where large volumes of CO2 will 

be injected into various geologic formations, and its movement will 

be closely monitored and studied. 

The outcome of these tests will be crucial to the public acceptance of zero-emission coal technology. 

Results of the Carbon Sequestration Regional Partnership’s analysis of the capacity in the United States to store carbon are very 

large. Deep saline formations could store all of the CO2 emissions 

for North America for over 500 years, according to their upper estimate. 

The storage capacity for enhanced oil recovery, however, is a lot 

lower. And it’s also geographically limited. We need IGCC demonstrations that are coupled with storage in deep saline formations. 

I would say that moving toward climate stabilization is an enormous global challenge—we need really big solutions, here. Partial 

solutions, such as 50 percent carbon capture, or ‘‘as good as natural 

gas,’’ just won’t cut it. We need to target capture levels that approach 90 percent. 

The increased cost for carbon capture and storage is a very major 

concern. For IGCC, our studies indicate that CCS adds about 36 

percent to the cost of electricity. For the combustion route, it adds 

over 80 percent. A large part of that huge cost increase is due to 

the large parasitic power that’s required to run the CCS equipment—it cuts the output of the plant by over 30 percent. 

I recently asked some of our systems analysis folks what I 

thought was a simple question—how much would it cost to implement CCS, nationwide, out to 2030? I guess I should have known 

that modelers don’t give simple answers to simple questions. 

They analyzed the scenario of a $30 a ton carbon tax, using a 

modification of EIA’s NEMS model, to project how widely CCS 

technology would penetrate, both in the new and retrofit market. 

Their analysis showed that 40 gigawatts in new IGCC would be 

added, along with 100 gigawatts of retrofitted CCS capacity. In addition, it would take another 30 gigawatts of new IGCC capacity, 

just around the carbon capture equipment on those older plants. 

The total tab attributed both to the CCS portion, alone, would be 

$240 billion—that’s $240 billion—and that’s just the capital component of the cost. 

We think that R&D is the key idea on how we’re going to get 

that enormous cost-adder down. Our program looks forward to get 

it to less than a 10 percent increase in the cost of electricity, and 

we are on a pathway to get there. My written testimony provided 

some specifics on the advantages we are pursuing. 

Turning to FutureGen—— 

Senator ENSIGN. Dr. Strakey? 

Mr. STRAKEY. Yes? 

Senator ENSIGN. If I may, Mr. Chairman? 

Did they do any cost comparisons? Because natural gas is projected to skyrocket in cost, were those comparisons done in relation 

to the increases projected in natural gas? 

26 

Mr. STRAKEY. Yes. The NEMS analysis allows other technologies to play against the higher cost of the $30 a ton carbon tax added 

on to coal, and you get a different mix of what would occur, including natural gas, nuclear, renewables, and so on. 

One of the issues that you may be interested in, is that the 

NEMS analysis, or the model, projects a fairly low price for natural 

gas—I don’t recall what it was offhand, but that would also, as you 

mentioned, impact the penetration of coal technology. 

Returning to FutureGen, I’ve provided some background on why 

we need one or more commercial-scale IGCC demonstrations, integrated with carbon capture and storage in deep saline formations. 

I also outlined why we need to demonstrate carbon capture levels 

approaching 90 percent. Basically, that is FutureGen, the keystone 

of our program. 

We’re facing major challenges, and I think we have an opportunity to lead the way with coal gasification and carbon capture 

and sequestration. 

Mr. Chairman, members of the Committee, thank you, that completes my statement. 

[The prepared statement of Dr. Strakey follows:] 

PREPARED STATEMENT OF DR. JOSEPH P. STRAKEY, JR., CHIEF TECHNOLOGY OFFICER, NATIONAL ENERGY TECHNOLOGY LABORATORY, U.S. DEPARTMENT OF ENERGY

Thank you Mr. Chairman and Members of the Committee. I appreciate this opportunity to provide testimony on the Department of Energy’s (DOE’s) Coal Gasification Research and Development (R&D) Program. 

The economic prosperity of the United States over the past century has largely 

been built upon an abundance of fossil fuels in North America. The United States’ 

fossil fuel resources represent a tremendous national asset. Making full use of this 

domestic asset in a responsible manner enables the country to fulfill its energy requirements, minimize detrimental environmental impacts, positively contribute to 

national security, and provide for the economic welfare of its citizens. 

Coal gasification, when done in conjunction with carbon capture and storage 

(CCS), is one technology option that offers our Nation an attractive approach to utilize our indigenous fossil energy resources in a more efficient and environmentally 

sound manner for producing clean, affordable power from coal with dramatically reduced carbon emissions. Coal gasification with CCS can also reduce the carbon impact of using coal to produce ultra-clean fuels for the transportation sector, substitute natural gas (SNG) to heat our homes and fuel our industrial sector, fertilizers to ensure an abundant food supply, and chemicals that play an integral part 

in our every day lives. 

Another coal gasification concept that could further reduce carbon dioxide (CO2) 

emissions is co-feeding coal and biomass into gasifiers to produce electricity or conventional transportation fuels. The transportation fuels application is referred to as 

the coal-biomass-to-liquids (CBTL) process. When combined with CCS, CBTL can reduce the greenhouse gas footprint of the fuel by 20 percent (compared to petroleum) 

with the addition of roughly 10–18 percent by weight biomass to the coal while remaining cost competitive at today’s world oil prices. Similar benefits in reduction 

of carbon emissions can be achieved by co-feeding coal and biomass for electricity 

generation in advanced gasification-based systems. 

Gasification-based processes are an efficient and environmentally friendly way to 

produce low-cost electricity, compared with other conventional coal-conversion processes. For power generation applications, gasification technology utilizes 30–50 percent less water and produces about one-half the amount of solid wastes as conventional power plants. By the very nature of the process, sulfur oxides, nitrogen oxides, mercury, particulates, and other emissions can be reduced to near-zero levels 

and gasification is often the least expensive approach for the capture of CO2. 

The gasification of coal dates back as far as the end of the eighteenth century, 

and by the middle of the nineteenth century the basic underlying principles of gasification were fairly well understood. The use of gasification was very prominent in 

the latter part of the nineteenth century and the first half of the twentieth century 

for the production of town gas for residential and industrial use. Although this apVerDate Nov 24 2008 13:10 May 24, 2012 Jkt 074322 PO 00000 Frm 00030 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\74322.TXT SCOM1 PsN: JACKIE
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plication has nearly vanished, due to its displacement by inexpensive natural gas 

and petroleum, new applications evolved in the industrial and manufacturing sectors. 

Gasification is at the heart of many processes that offer industry low-cost, reliable, and highly-efficient options for meeting a host of market applications. Gasification-based systems are capable of utilizing all carbon-based feedstocks, either separately or in combination with one another, including coal, petroleum coke, biomass, 

municipal and hazardous wastes. In the gasification process, carbon-based feedstocks are converted in the gasifier in the presence of steam and oxygen at high 

temperatures and moderate pressure to synthesis gas, a mixture of carbon monoxide 

and hydrogen. The synthesis gas is cleaned of particulates, sulfur, ammonia, 

chlorides, mercury, and other trace contaminants to predetermined levels consistent 

with further downstream processing applications. At this point, various options exist 

for the utilization of the synthesis gas. In one option, Integrated Gasification Combined Cycle (IGCC) for the production of electricity, the cleaned synthesis gas is 

combusted in a high-efficiency gas turbine/generator, and the heat from the turbine 

exhaust gas is extracted to produce steam to drive a steam turbine/generator. Furthermore, IGCC can be readily adapted for concentrating, capturing, and sequestering CO2. In addition to being used for power generation, a portion or all of the synthesis 

gas can be chemically shifted (by reaction with steam) to a mixture of hydrogen (H2) 

and CO2. Here the H2 and CO2 can be separated, with the hydrogen being used in 

the gas turbine or highly efficient fuel cells for the production of electricity in a carbon-constrained world, while the CO2 can be captured and sequestered. The shifted 

synthesis gas can also be processed in chemical reactors to produce high-quality 

transportation fuels, SNG, and chemicals. Gasification-based systems are the only 

advanced processes within the Department’s research portfolio that are capable of 

co-producing both power as well as a wide variety of commodity and premium products to meet future market requirements. 

Today, there are nineteen gasification plants operating in the United States. Nine 

of these plants use natural gas to produce carbon monoxide and hydrogen for synthesis of chemicals and petroleum refining, four use petroleum-based liquids for 

chemicals production, and six operate using solid feedstocks, i.e., coal and/or petroleum coke. Of the six solid-feed gasification plants, two produce chemicals, three operate as IGCC power plants, and one produces SNG. The following are examples of 

gasification plants in operation in the United States today. 

The largest operating coal gasification plant in the United States is the Dakota 

Gasification Company’s Great Plains Synfuels Plant in Beulah, North Dakota. This 

plant was constructed with a loan guarantee from the Department of Energy and 

began operation in 1984. The plant has a capacity for producing up to 170 million 

cubic feet per day of SNG from nearly 18,500 tons per day of North Dakota lignite 

from an adjacent mine. The SNG is injected into an existing natural gas distribution 

pipeline to the Midwest. It should be noted that while the plant was a technical success, it was not a financial success: in 1985 the project sponsors defaulted on the 

loan, due in part to falling natural gas prices at the time, and the U.S. Treasury 

paid $1.550 billion to cover the guarantee. 

Eastman Chemical Company operates two coal gasifiers at its Kingsport, Tennessee, chemical complex. Approximately 1,200 tons per day of eastern bituminous 

coal is converted to synthesis gas that is used as the building blocks for nearly 75 

percent of the chemical products produced at the plant. Many of the products from 

this plant find their way into every day household products such as scotch tape, 

screwdriver handles, Kodak 35-mm film, and flat screen TV panels. In addition, 

products such as Tylenol and NutraSweet also have their origins in coal from this 

facility. 

The Coffeyville Resources Nitrogen Fertilizer plant located in Coffeyville, Kansas, 

is the only other solid-feed gasification plant focusing on chemicals production, 

namely ammonia and urea fertilizer. This plant began operation in 2000 and today 

is the lowest cost manufacturer of nitrogen-based fertilizer products in North America. 

Three IGCC power plants using solid feedstocks are in operation today in the 

United States—Tampa Electric’s Polk Power Station in Tampa, Florida (250 MWe); 

SG Solutions Wabash River plant in West Terre Haute, Indiana (262 MWe); and 

Valero’s Delaware Clean Energy Cogeneration project in Delaware City, Delaware 

(160 MWe). The Florida and Indiana projects both received Federal cost-share 

through DOE’s Clean Coal Technology Program. These two projects successfully 

demonstrated coal-fueled IGCC and have been instrumental in giving the utility industry confidence in IGCC technology and in generating commercial interest in 

IGCC deployment. 

28 

The Department’s Office of Fossil Energy (FE), which manages research efforts 

within the Gasification Program that are implemented by the National Energy 

Technology Laboratory, recognizes the complex energy and environmental challenges facing America today. To address these needs, FE has a core coal R&D program that provides for the development of affordable and environmentally effective 

technologies to use coal. This core coal R&D program includes not only the Coal 

Gasification Program but also the Advanced Research (advanced materials, sensors 

and controls, and computational modeling), Advanced Turbines, Carbon Sequestration, Fuel Cells, Hydrogen and Fuels, and Innovations for Existing Plants Programs. 

DOE is developing advanced gasification technologies to meet the most stringent 

environmental regulations in any state, and to facilitate the efficient capture of CO2

for subsequent sequestration—a pathway to ‘‘near-zero atmospheric emission’’ coalbased energy. Gasification plants are complex systems that rely on a large number 

of interconnected processes and technologies. Advancements in the state-of-the-art, 

as well as development of novel approaches, could expand technical pathways and 

enable gasification to meet the demands of future markets while contributing to energy security. 

Technical Issues/Hurdles—A technical report prepared by the Gasification Program in July 2002, ‘‘Gasification Markets and Technologies—Present and Future: 

An Industry Perspective,’’ specifically outlines key technology issues affecting the 

commercial acceptance and deployment of gasification-based processes. Our coal research efforts in gasification are aimed at addressing these key issues, and good 

progress continues to be made toward their resolution. Foremost at that time was 

the need to improve process reliability and reduce capital cost. More recently, our 

research has expanded to address the cost and integration of gasification, particularly IGCC, with CCS. 

Areas identified as significantly impacting process reliability included refractory 

wear, feed-injector life, and high-temperature measurement instrumentation. Areas 

targeted for capital cost reduction efforts included improved feeding systems capable 

of handling multiple feedstocks, lower cost air-separation technologies, and hightemperature gas cleaning capable of deep removal of all contaminants. Some of the 

significant research programs addressing these issues are described below. 

Ion Transport Membranes—Conventional cryogenic air-separation technologies 

used in today’s gasification plants are both capital and energy intensive. Typically, 

the cryogenic air separation constitutes 12–15 percent of the cost of an IGCC plant 

and can consume upwards of 10 percent of its gross power output. A promising technology being developed today that offers significant potential for cost and parasitic 

power reductions are known as Ion Transport Membranes (ITM). This technology 

has been under development by the Department, in partnership with Air Products 

and Chemicals, Inc. (APCI), for nearly 10 years. During this time, ITM technology 

has progressed from fundamental materials development to the operation of fullscale membranes and half-size modules in a 5 ton-per-day unit operating at APCI’s 

Sparrows Point industrial gas facility near Baltimore, Maryland. Engineering analyses have consistently shown nearly a 35 percent reduction in the capital cost of 

the air-separation unit for an IGCC plant and nearly a one-point gain in thermal 

efficiency. To achieve maximum benefit, the ITM must be integrated with a gas turbine. The program is in its third phase of development that will culminate in the 

integrated testing of a 150 ton-per-day process module with a gas turbine that will 

be located at an existing coal gasificationsite in 2010. Upon successful completion 

of this phase, plans are being discussed for further scale-up to a 1,500 to 2,000 tonper-day prototype unit. 

High-Temperature Gas Cleanup—Removing sulfur and other impurities from coalderived gas in an IGCC plant generally accounts for 10–12 percent of the capital 

investment of the plant to meet recent emissions standards. It is recognized that 

deep-cleaning technologies are required to meet future near-zero emission standards 

from coal-fired power plants, as well as achieve the desired synthesis gas purity for 

the production of transportation fuels and chemicals. Technologies for such deep 

cleaning are available, but are very costly and inefficient due to their low temperature of operation. Development of innovative deep-cleaning technologies that operate 

at process temperatures consistent with downstream processing applications, i.e., 

400 to 900 degrees Fahrenheit, would provide significant benefits. Although several 

approaches are being investigated, the most advanced employs a high-temperature, 

zinc-based sorbent in a transport reactor. Over 3,000 hours of operation with this 

particular sorbent have recently been completed using coal-derived synthesis gas at 

Eastman Chemical Company. Planning is in progress for slipstream testing of a 50- 

MWe size unit at a commercial gasificationsite. 

Coal-Feed Pumps—The development of coal-feed pumps will reduce the cost and 

improve the efficiency of all gasification-based processes. They will also improve the 

29 

economics of utilization of vast low-rank coal reserves. With DOE support, Stamet 

Incorporated successfully developed a single-stage rotary feed pump that has the capability of injecting high-moisture coal into the high-pressure gasifier—up to 1,000 

psig. In 2007, General Electric purchased Stamet for use with their gasifier technology to make their technology suitable for low-rank coal gasification. Concurrently, DOE was engaged with Pratt & Whitney Rocketdyne to also develop a coalfeed pump. Detailed design of a 400 ton-per-day pump is in progress and testing 

is scheduled to begin in late Fiscal Year 2009. 

H2 and CO2 Separation Membranes—Today’s technologies for CO2 removal impose 

significant impacts on the thermal efficiency and capital cost of IGCC plants. It is 

believed that this impact can be greatly reduced through the use of advanced technologies such as membranes for separation. Furthermore, cost-effective and efficient 

gas separation technologies are vital in any chemical process operation and will impact the overall cost of the system. For the production of hydrogen from coal, gas 

separation is required for the separation of the shifted synthesis gas stream into 

pure H2 and CO2 streams. Separation of hydrogen from shifted synthesis gas is a 

key unit operation of any gasification-based hydrogen production system. The Gasification Program and its partner, Eltron Research and Development Company, are 

pursuing the development of a dense metallic-based membrane to reduce the cost 

and increase the performance of hydrogen separation. This membrane has achieved 

nearly all of DOE’s 2015 performance goals for membrane-based systems. The Fuels 

program is also working on hydrogen separation technologies. 

Coal/Biomass Gasification—The process for turning gasified coal and/or biomass 

into liquid transportation fuels is mature and commercially available, with technology improvements driven by the marketplace. However, the technology for cofeeding and gasifying coal-biomass mixtures is not commercially available. DOE’s 

program includes development of technology for co-feeding and gasifying coal/biomass for electricity generation application. As with much of DOE’s gasification program, DOE’s FY 2009 coal/biomass research targets electricity generation applications, but could also be used by the private sector for other applications, such as 

production of transportation fuels. Co-feeding of coal and biomass up to about 20 

percent by weight is well within the range of operability for large-scale plants. Operators of the NUON IGCC plant in Buggenum, The Netherlands, successfully fed a 

mixture of coal and 30 percent (by weight) demolition wood into a high-pressure, 

entrained-flow gasifier. 

Gasification and Carbon Sequestration—DOE is taking a leadership role in the 

development of CCS technologies. The Carbon Sequestration Program is addressing 

the key challenges that confront the wide-scale deployment of capture and storage 

technologies through research on cost-effective capture technologies; monitoring, 

mitigation, and verification technologies to ensure permanent storage; permitting 

issues; liability issues; public outreach; and infrastructure needs. Gasification technology holds substantial promise as the best coal conversion technology option to 

utilize carbon capture technologies. The Gasification Program is aggressively pursuing developments to reduce the cost of carbon capture so that the cost of electricity to the public will result in an increase of less than 10 percent for new gasification-based energy plants. 

FutureGen—The Department’s FutureGen program offers a key opportunity to 

validate gasification technology coupled with CCS in commercial settings. In light 

of recent proposals for over 30 gasification-based commercial coal plants throughout 

the United States, and the potential siting issues that may require these plants to 

have carbon capture capability, the restructured FutureGen focuses on multiple gasification technology demonstrations with CCS in commercial plant settings. With 

this new strategy, the Department will help fund the CCS portion of the demonstration unit of the overall plant, thereby limiting the Department’s, and taxpayer’s, 

cost exposure. This restructured approach allows DOE to maximize the role of private sector innovation, provide a ceiling on Federal contributions, and accelerate the 

Administration’s goal of increasing the use of clean energy technologies to help meet 

the steadily growing demand for energy while also mitigating greenhouse gas emissions. 

In today’s business environment, markets and market drivers are changing at a 

rapid pace. Environmental performance is a much greater factor now than in previous years as emission standards tighten. In addition, the reduction of CO2 emissions is one of the major challenges facing industry in response to global climate 

change. To help meet these challenges, there is a need for more environmentally 

sound, flexible, efficient, and reliable systems that still meet the ever-present demand for higher profitability. Gasification is a technology that is poised to meet 

these requirements. 

30 

Mr. Chairman, Members of the Committee, this completes my statement. I would 

be happy to take any questions you may have. 

Senator KERRY. Thank you, Dr. Strakey. I look forward to following up on that. 

Mr. Mudd, FutureGen Alliance? 

STATEMENT OF MICHAEL J. MUDD, CEO, 

FUTUREGEN ALLIANCE, INC. 

Mr. MUDD. Thank you, Mr. Chairman. 

It’s an honor to be here, thank you also, Senator Ensign, Senator 

Stevens. My name is Michael Mudd—— 

Senator KERRY. Pull that there, will you? Would you just pull it 

toward you? There you go. 

Mr. MUDD. Well, my name is Michael Mudd, I’m the Chief Executive Officer of the FutureGen Alliance, formed at the request of 

the U.S. Department of Energy to co-fund, design and construct the 

world’s first near-zero emission IGCC plant with 90 percent CO2

capture and carbon sequestration. 

The Alliance is a nonprofit, global consortium comprised of 13 energy and power companies throughout the world. Prior to my current position, I had the honor of working for over 30 years at American Electric Power, where I spent a lot of time managing clean 

coal technology projects, including IGCC. 

My remarks today will address the FutureGen partnership—— 

Senator KERRY. American Electric Power has a couple of plants 

that are IGCC now, right? Aren’t they building one in Ohio? 

Mr. MUDD. AEP is planning to build two IGCC plants—one in 

Ohio, and one in West Virginia, that is correct, Mr. Chairman. 

Senator KERRY. Right. 

Mr. MUDD. My remarks will address the FutureGen partnership 

and the impact of the DOE’s proposed restructuring. The details 

are in my written remarks, and what I’d like to talk about today 

is three things which I will now summarize. 

The first one is FutureGen located at Mattoon, Illinois is in the 

national interest, and is advancing IGCC technology with carbon 

capture and sequestration faster and further than any other project 

in the world. Climate technologies must be globally accepted and 

globally deployed in order for them to have maximum impact. 

FutureGen at Mattoon includes international involvement at an 

unprecedented level, with 13 companies from 6 continents taking 

part. As a nonprofit enterprise, the FutureGen Alliance will be in 

a position to broadly share the information from the project. This 

will help to deploy such near-zero emission power plants throughout the world. 

FutureGen at Mattoon will also meet all of the goals of the DOE 

program, most importantly—as Dr. Strakey said—90 percent carbon capture, which DOE has reported to Congress as critical to our 

energy future. 

FutureGen at Mattoon also fully integrates IGCC and carbon 

capture and sequestration technology. The size of the components 

are at a full-commercial scale, therefore it will validate that performance and help to get it into the marketplace more quickly. 

With respect to progress, FutureGen at Mattoon has 5 years of 

demonstrated success, using a first-of-a-kind siting process which 

31 

can, and should, serve as a model for future plants, a site has been 

ready—has been picked, and is ready to go. This includes identifying all of the very complex issues associated with injecting CO2

in these geologic formations—the legal, the liability, the regulatory 

and geology—all very critical, all are paving new paths that have 

not been done before. 

A nearly 2,000-page final Environmental Impact Statement has 

been issued by the Department of Energy, which proves that the 

Mattoon site is acceptable from an environmental perspective. A 

team of nearly 50 engineers and scientists have completed an initial design of the plant, and a cost for the plant. 

FutureGen at Mattoon has made more progress in advancing 

IGCC technology with carbon capture and sequestration than any 

other project in the world. 

The second theme is about the project costs. It is important to 

remember that all major energy projects are being impacted by 

rapidly rising prices of commodity, equipment, steel, concrete, and 

so on. FutureGen at Mattoon’s unique financing structure mitigates 

taxpayer exposure. The Alliance members have pledged approximately $400 million to the project, and will return all of the estimated $300 million in plan revenue back to the project, will direct 

all of the post-project revenue from the sale of power to benefit 

public R&D. 

Industry financial contributors will never receive a single dollar 

of financial return. Such a financial arrangement is unprecedented 

in such a public-private partnership. 

The final theme of my testimony is that the DOE’s proposed restructuring falls short of addressing the national need for technology enhancement. The restructuring will result in an unacceptable termination of FutureGen at Mattoon, in favor of projects that 

will delay technology development by 5 years, or more. 

DOE’s proposed restructuring leaves many unanswered questions, which are addressed in my written testimony. It is my hope 

that the ongoing Congressional review surrounding IGCC, and carbon capture and sequestration, will bring an appropriate spotlight 

on the urgent need for large-scale projects. There remains an opportunity for the U.S. Government to reassert its position that 

FutureGen at Mattoon is a top priority project for advancing IGCC 

and CCS, with carbon capture and sequestration. 

FutureGen at Mattoon should not be terminated, but instead, we 

need additional projects. In this way, DOE can reassume its position as a global leader in near-zero emission coal plants, and CCS 

development. 

That concludes my opening remarks, and I welcome further questions. 

Thank you. 

[The prepared statement of Mr. Mudd follows:] 

PREPARED STATMENT OF MICHAEL J. MUDD, CEO, FUTUREGEN ALLIANCE, INC. 

The FutureGen program is a global public-private partnership formed to design, 

build, and operate the world’s first near-zero emission coal-fueled power plant with 

90 percent capture and storage of carbon dioxide (CO2). It will determine the technical and economic feasibility of generating electricity from coal with near-zero 

emission technology. FutureGen has 5 years of progress behind it and is positioned 

to advance Integrated Gasification Combined Cycle (IGCC) and carbon capture and 

32 

sequestration (CCS) technology faster and further than any other program in the 

world. The location of the plant will be Mattoon, Illinois. The nonprofit structure 

of the FutureGen Alliance, and involvement of thirteen companies that operate on 

six continents, is consistent with its mission to facilitate rapid deployment of nearzero emission technology not only in the United States, but throughout the world. 

Climate change is one of the most pressing environmental concerns, and it is clear 

that Congress intends to develop policies to address this concern. Irrespective of 

which specific climate policy is ultimately adopted by the U.S., the success of that 

policy and our economic future, will hinge on the availability of affordable low-carbon technology. Nuclear, renewables, biomass, and efficiency will all be part of the 

low-carbon technology solution. However, given that coal is used to generate over 

50 percent of the electricity in the U.S. and is projected to remain the backbone of 

the U.S. electricity system for most of this century, and the growing economies of 

China and India will be fueled with coal plants, the availability of affordable, nearzero emission coal technology, incorporating carbon capture and sequestration, is essential to our future energy security. 

The Federal Government has a pivotal role to play in fostering the development, 

demonstration and deployment of near-zero emission coal technology. It is important 

that, as a Nation, we invest at the scale required to develop, prove, and deploy CCS 

technologies to the marketplace. While estimates vary, the required investment is 

certainly in excess of $10 billion over the coming decade. This investment in our Nation’s future must be supported by the development and demonstration of near-zero 

emission coal technologies and CCS in a variety of applications. 

The U.S. Department of Energy (DOE) is to be commended for its vocal support 

of near-zero emission coal technology, including CCS. Its support of this technology 

was recognized in its support of the FutureGen program as originally envisioned, 

but a recent proposal to restructure FutureGen fails to recognize the scale of the 

challenge that this Nation, and indeed the world, is facing. DOE’s proposal to restructure the FutureGen program will delay technology development and integrated 

demonstration of commercial scale CCS by 5 years or more. It backs away from a 

nonprofit partnership that was created, at the request of DOE, to act in the public 

benefit and broadly share its technical results throughout the world. It rebuffs the 

participation of international companies (and countries) that are critical to the ultimate deployment of clean coal technology around the world, and it undermines the 

reliability of the U.S. Department of Energy—and the United States—as a dependable partner. 

Therefore, regardless of what other projects or what type of structuring DOE proposes, it is essential that the Department reaffirms the Unites States’ position as 

a global leader in near-zero emission coal technology and CCS development by 

maintaining the position that DOE has stated numerous times prior to its announcement of restructuring: that FutureGen at Mattoon is the top priority program 

in advancing CCS technologies. 

FutureGen at Mattoon 

FutureGen, located in Mattoon Illinois, is in the national interest and is advancing IGCC technology with CCS faster and further than any other project in the 

world. 

• FutureGen at Mattoon offers DOE an opportunity to beat its proposed timeline. 

DOE’s January 15, 2008 Request for Information (RFI) suggests an on-line date 

of 2015 for projects using its restructured plan. The FutureGen Alliance has already delivered 5 years of progress, including contract negotiations, an enthusiastic and committed local community, a site that is technically and legally ready 

to go, a design and cost estimate, a final environmental impact statement, vendor relationships, and a team of fifty engineers and scientists. No fully integrated, near-zero emission power-plant project in the world can compete with 

FutureGen in terms of its ability to move forward with urgency on the required 

technology development and demonstration. 

• FutureGen at Mattoon will meet or exceed all DOE emissions and CO2 capture 

goals. All emissions and CO2 capture criteria included in the 2004 FutureGen 

Report to Congress and DOE’s current Request for Information (RFI) will be 

met by FutureGen at Mattoon, including 90 percent CO2 capture. It is imperative that DOE maintain the requirement of 90 percent CO2 capture from the 

entire facility for the FutureGen program. 

• FutureGen at Mattoon is fully integrated and commercial scale. FutureGen at 

Mattoon incorporates a commercial-scale gasifier and commercial-scale ‘‘Frame 

7’’ turbine. As configured, and with the commitment to share lessons learned 

33 

widely, it gives industry a chance to learn about the cost, performance, and operating strategies for an integrated system with CCS. 

• Public benefit and information sharing is a hallmark of FutureGen at Mattoon. 

As a nonprofit enterprise, the FutureGen Alliance will broadly share information from the project, facilitating the deployment of commercial, near-zero emission power plants throughout the world. It is appropriate for DOE to provide 

cost sharing for additional commercial CCS projects to facilitate deployment of 

CCS technology, but it must recognize that commercial projects by their very 

nature will feature protection of technological know-how and intellectual property within individual companies rather than sharing it for broad benefit. 

• International involvement is essential to the rapid deployment of CCS technologies, and FutureGen at Mattoon is a model that provides international involvement at an unprecedented level. Thirteen companies with operations on six 

continents are participating as members of the Alliance. Climate technologies 

must be globally acceptable and globally deployed, or they will not be effective. 

International participation has been exceptionally well-managed and has been 

a cornerstone of the information sharing in the program. No other project or 

program can replicate FutureGen at Mattoon’s level of international involvement. 

• FutureGen at Mattoon provides a platform for testing advanced technologies, 

which accelerates technology development and saves the taxpayer money. Once 

built, and power generation, carbon capture, and sequestration operations are 

underway, FutureGen at Mattoon can serve as a test bed for advanced technologies emerging from DOE’s Fossil Energy R&D program and industry R&D 

efforts. Such testing will not interfere with the primary mission of the facility 

to prove integrated CCS technology at a 90 percent capture level and sequester 

a minimum of one million tons per year of CO2, and to develop and prove costeffective approaches to advancing CCS technology. Alternative testing approaches will be far more expensive. Areas where DOE expects advancements 

to occur include oxygen production, gasifier improvements, gas clean-up, H2 and 

CO2 separation, H2 turbine advancements and fuel cells. By proposing to end 

its support of FutureGen at Mattoon, DOE will be increasing the cost and difficulty of testing the very advanced technologies that its program managers 

seek to develop and deploy. 

FutureGen at Mattoon’s Costs 

All major, global energy infrastructure projects are being impacted by rapidly rising commodity and equipment costs. FutureGen at Mattoon is no exception. Other 

IGCC and CCS projects also are no exception. However, FutureGen at Mattoon’s 

unique financing structure mitigates taxpayer exposure. The Alliance has pledged 

approximately $400 million to the program, will return 100 percent of the estimated 

$300 million in plant revenues back to the program, and will direct 100 percent of 

post-program electricity revenues to public benefit R&D. After the program is complete, if the plant is ever sold, the Alliance has advised the DOE that it would be 

eligible for partial to full repayment. Industry financial contributors will never receive a single dollar of financial return. This represents an unprecedented level of 

commitment by the Alliance membership to a public-private partnership. The Alliance is willing to make this commitment because this investment is squarely in the 

interest of both the Nation and the world. 

With respect to the commercial status of IGCC without CCS, while there are some 

IGCC plants being planned, the marketplace is still in its infancy. Only one IGCC 

without CCS is under construction and that plant received substantial government 

subsidies and required a major increase in electricity rates for it to proceed. Of the 

other IGCC plants in the planning stage, very few have been able to secure full financing and/or regulatory approval. The high cost of new power plants coupled with 

the difficulty in getting either bank financing or regulatory approval has resulted 

in the cancellation of many coal plants. Further, taking a broader look at coal-related plants of all technologies, according to Source Watch, in 2007 alone, 59 proposed plants were cancelled, abandoned, or put on hold, and of those plants remaining, few are IGCC’s with real prospects of being built. The challenges in the marketplace, even when CCS is not considered, are clear. The addition of CCS with 90 percent capture fundamentally changes the underlying IGCC plant configuration—it is 

not a simple addition, it adds significant additional cost and complexity. 

Thus, it is an appropriate role for the Federal Government to take on the challenge of building the world’s first IGCC with 90 percent CCS. In the current marketplace environment, on its own, the technology simply will not come forward. With 

34 

the continued funding from the U.S. DOE, FutureGen will have a high probability 

of proceeding. 

DOE’s Proposed Restructuring 

The Alliance believes that it is in the national interest to complement FutureGen 

at Mattoon with additional projects in a variety of engineered applications and a 

variety of geologic formations. However, complementary projects must not come at 

the expense or delay of the number one priority, FutureGen at Mattoon. Further, 

it is doubtful that real projects with CCS technology that capture 90 percent of the 

CO2 and sequester the CO2 in geologic formations can be brought to fruition absent 

the trailblazing of FutureGen at Mattoon. Currently, DOE’s proposed restructuring 

leaves many unanswered issues that are of concern. Some of the specific concerns 

about the DOE proposed restructuring include: 

DOE’s schedule under the restructuring proposal is unrealistic. DOE has an important obligation to the taxpayer to follow comprehensive contracting processes, conduct technology reviews, and prepare an environmental impact statement on any new project. The schedule in the RFI (i.e., a proposed on-line date 

of 2015) is not realistic for a project that meets 100 percent of the stated goals. 

Many potential industrial partners are unfamiliar with DOE’s required practices, and it is important that the DOE inform them of a reasonable schedule 

so that they can properly conduct the project and deal with their third-party 

investors. Overly optimistic schedules are a disservice to Congress, industry, 

and the public. 

Based on my experience, I would envision the following as a fast-track schedule 

for DOE to identify an alternative, fully integrated project that meets all of the 

existing performance goals for the FutureGen program: 

» 2009+: project selection and cooperative agreement negotiation 

» 2012: completion of preliminary design, environmental impact assessment and 

record of decision 

» 2013: completion of detailed design and procurement of major technology components 

» 2017: completion of construction 

» 2018: initial operation 

» 2022: completion of test period 

• DOE’s restructured approach has problematic business parameters. DOE’s proposal implies that 90 percent capture simply involves the addition of new technology to an existing IGCC. It does not. The complex integration of CCS into 

a commercial IGCC plant will entail significant modifications to many other 

systems, including commercial systems inside the base plant. It would also 

largely require a restart of design work done to date on the base commercial 

plant. Thus, the government, its procurement rules, and its oversight practices 

could easily extend into the commercial, for-profit power plant. Further, applying FutureGen funds to a project with anything appreciably less than capturing 

90 percent of the total CO2 emissions from the entire plant would fall short of 

what is needed to rapidly develop near-zero coal plants. 

• DOE’s restructured approach does not address the increased marginal cost of 

electricity due to adding CCS to a plant. The modified plant that DOE proposes 

that industry build will cost substantially more to operate than a traditional 

plant. DOE’s RFI is largely silent on operating costs. Adding CCS to an IGCC 

plant is expected to increase the cost of electricity by as much as 50 percent 

and the marginal production cost by as much as 20 percent. Because power 

plants dispatch electricity to the grid based on their marginal operating cost, 

the approach DOE proposes could result in a plant that is too expensive for industry to operate. 

• Increased appropriations will be required to offset Federal taxation. DOE is proposing moving away from its partnership with the nonprofit Alliance to providing Federal funds for a for-profit entity. While it is appropriate for DOE to 

work with for-profit and nonprofit entities, the precedent in the Clean Coal 

Power Initiative is that DOE grants awarded to for-profit entities can be subject 

to taxation by the IRS, if determined to be income. Thus, whereas 100 percent 

of the funding going to FutureGen at Mattoon goes to on-the-ground technology 

and operations, under DOE’s new program, DOE will need increased appropriations if it intends to make the same ultimate on-the-ground investment in technology and operations. This could result in either: (1) hundreds of millions of 

35 

dollars of additional appropriations to offset taxes or (2) a major dilution of 

DOE’s program investment through taxation. 

• DOE appropriately retained the 90 percent capture goal in its RFI and must do 

so in any awarded projects. The FutureGen program has identified 90 percent 

CO2 capture as an important requirement to advance CCS technology. This 

level of CO2 capture has significant impact on the design of many critical components of the facility, such as the combustion turbine, gas clean-up system, and 

syngas clean-up system. It would be a serious mistake if this target level is relaxed. Ninety percent is a technical goal designed to ensure a sustainable future 

for coal in a carbon-constrained world. Today’s commercial projects cannot technically or economically achieve this goal and DOE’s program should focus on 

bold technological advances not incremental change. 

• Plant revenue must go to the industrial partner. In a commercial project, it is 

expected that 100 percent of revenue would need to go to the industry partner. 

Unlike FutureGen at Mattoon, in which DOE shared in the project revenues 

substantially offsetting Federal investment, for projects conducted under DOE’s 

new approach, a successful commercial project would insist that plant revenues 

go to the industrial partner so that private sector participants can generate a 

commercial return. 

In its 2004 report ‘‘FutureGen Integrated Hydrogen and Electric Power Production and Carbon Sequestration Research Initiative’’, DOE acknowledged the necessity for the type and level of risk sharing associated with FutureGen at Mattoon, 

if technology is to advance at the required pace. In its report, DOE said: 

‘‘FutureGen’s integration of concepts and components is key to providing technical and operational viability to the generally conservative, risk-adverse coal 

and utility industries. Integration issues such as the dynamics between upstream and downstream subsystems (e.g., between interdependent subsystems 

such as the coal conversion and power and hydrogen production systems and 

carbon separation and sequestration systems) can only be addressed by a largescale integrated facility operation. Unless the production of hydrogen and electricity from coal integrated with sequestrating carbon dioxide can be shown to 

be feasible and cost competitive, the coal industry will not make the investments necessary to fully realize the potential energy security and economic benefits of this plentiful domestic energy resource.’’ 

Technology advancements and market changes in the last 5 years have not 

changed this need for a full scale demonstration envisioned in DOE’s report and 

FutureGen at Mattoon. 

There is no program in the world that can move near-zero emission power and 

CCS faster or further than FutureGen at Mattoon. The FutureGen Alliance is nonprofit, includes unprecedented international involvement and information sharing, 

and has a site that is technically and legally ready to go. Alternatives will cost the 

country 5 years or more of delay and/or deliver less in terms of results. 

As Congress and the administration debate the appropriate structure for the 

FutureGen program, the Alliance urges that all of these factors be taken into account. FutureGen at Mattoon should be maintained as a global flagship program 

that is the Nation’s top priority for advancing near-zero emission coal technology, 

and complementary projects should be added to the program as the budget allows. 

Senator KERRY. Thank you, Mr. Mudd. 

Mr. Hawkins? Thanks for your many years of effort at this. 

STATEMENT OF DAVID G. HAWKINS, DIRECTOR, CLIMATE 

CENTER, NATURAL RESOURCES DEFENSE COUNCIL 

Mr. HAWKINS. Thank you very much, Mr. Chairman, for inviting 

me to present NRDC’s views on carbon capture, on coal, climate 

protection, and the role of gasification. 

Today, coal use and climate protection are on a collision course, 

and coal is at the center of that collision. Coal is ubiquitous, it is 

abundant, and if one ignores its environmental costs, it comes to 

the marketplace at low cost. 

36 

Because it’s so abundant, it’s going to be very difficult to convince political leaders to walk away from coal. It would take decades to do it, in my opinion, and we don’t have decades. 

So, a critical need today is to develop a method for changing the 

investments in the coal plants that are being built—being proposed 

here in the United States as you mentioned—and being built very 

rapidly in countries like China. 

The reason that this is so critical is the magnitude of the global 

warming pollution that would come from those new coal plants, 

and how much more difficult it would make our job. 

There are about 3,000 new coal plants that are on the drawing 

boards, globally, for construction in the next 25 years—about twothirds of those in the developing world, and about 40 percent in 

China. If those plants operated for 60 years—which is a typical lifetime—and they released all of their CO2 into the atmosphere, the 

total would be astounding—it would be about 750 billion tons of 

carbon dioxide. To put that number in perspective, that’s 30 percent more emissions than all emissions from coal use in previous 

human history, and that’s with 25 years worth of investments in 

coal plants alone. 

So you can see that we’ve got a huge train coming at us that we 

have to address without delay. Otherwise we’re going to make this 

problem of protecting the climate, impossible. 

There is an answer for the coal plants that are built: carbon capture and geologic disposal technologies are ready for use today and 

gasification is a commercially demonstrated component of that system. 

What we need is not an R&D program, we need a technology 

framework for deploying these technologies, and a policy that is 

supportive. 

We recommend three parts of a package, in order to make this 

happen. First, enactment of a comprehensive cap-and-trade legislation on global warming emissions. We need this, in order to put the 

Nation on a path to achieve the needed reductions; we need it to 

provide flexibility that can keep costs low; and most importantly we 

need it to provide a reason for investing in carbon capture technology in the first place. Without an emissions cap program, and 

without a requirement for capture, there’s no economic rationale to 

capture the carbon. 

The second element of this—to get the program, to get this deployment happening faster, is what we call a low-carbon generation 

obligation. This would overcome a major financial problem. Right 

now, someone wants to built a new project—absent specific large 

government subsidies, all of the costs would fall on the ratepayers 

of that particularly company, and not surprisingly, a lot of them 

are hesitant to do that. 

A low-carbon generation obligation would have the merit of 

spreading the incremental costs of these first projects over the entire electric generating system, and providing this technology to be 

demonstrated at very low cost to any individual ratepayer. 

The third thing that we recommend is a new source performance 

standard for new coal generation. We simply shouldn’t build new 

coal plants without capturing the carbon. 

37 

The first rule of holes is, when you’re in one, stop digging. And 

building a new coal plant that emits all of its CO2 in the atmosphere will simply make us dig our hole deeper. 

But, if we combine these measures, we can stimulate the immediate deployment of this technology. I would say, today, that if 

something like the Lieberman-Warner climate bill were law today, 

that the FutureGen project would be under construction today—we 

wouldn’t be sitting here talking about why it was encountering all 

of these obstacles—it would be built. 

So, I would say, in concluding, that if Congress takes steps to 

enact these policies, and programs in this Congress, we’ll be on our 

way to addressing this problem, we’ll be on our way to avoiding the 

lock-in of a huge amount of new global warming emissions associated with new coal plants, and we will be able to demonstrate the 

commercial reliability and feasibility of these new technologies, and 

that is something that the world will take notice of. And it is something that will engage countries like China, and India, and help us 

solve this problem. 

Thank you. 

[The prepared statement of Mr. Hawkins follows:] 

PREPARED STATEMENT OF DAVID G. HAWKINS, DIRECTOR, CLIMATE CENTER, NATURAL RESOURCES DEFENSE COUNCIL

Thank you for the opportunity to testify today on coal gasification and carbon capture technologies. My name is David Hawkins. I am Director of the Climate Center 

at the Natural Resources Defense Council (NRDC). NRDC is a national, nonprofit 

organization of scientists, lawyers and environmental specialists dedicated to protecting public health and the environment. Founded in 1970, NRDC has more than 

1.2 million members and online activists nationwide, served from offices in New 

York, Washington, Los Angeles and San Francisco, Chicago and Beijing. 

Today, the U.S. and other developed nations around the world run their economies largely with industrial sources powered by fossil fuel and those sources release 

billions of tons of carbon dioxide (CO2) into the atmosphere every year. There is national and global interest today in capturing that CO2 for disposal or sequestration 

to prevent its release to the atmosphere, something that can be achieved with commercially demonstrated coal gasification systems. To distinguish this industrial capture system from removal of atmospheric CO2 by soils and vegetation, I will refer 

to the industrial system as carbon capture and disposal or CCD. 

The interest in CCD stems from a few basic facts. We now recognize that CO2

emissions from use of fossil fuel result in increased atmospheric concentrations of 

CO2, which along with other so-called greenhouse gases, trap heat, leading to an increase in temperatures, regionally and globally. These increased temperatures alter 

the energy balance of the planet and thus our climate, which is simply nature’s way 

of managing energy flows. Documented changes in climate today along with those 

forecast for the next decades, are predicted to inflict large and growing damage to 

human health, economic well-being, and natural ecosystems. 

Coal is the most abundant fossil fuel and is distributed broadly across the world. 

It has fueled the rise of industrial economies in Europe and the U.S. in the past 

two centuries and is fueling the rise of Asian economies today. Because of its abundance, coal is cheap and that makes it attractive to use in large quantities if we 

ignore the harm it causes. However, per unit of energy delivered, coal today is a 

bigger global warming polluter than any other fuel: double that of natural gas; 50 

percent more than oil; and, of course, enormously more polluting than renewable energy, energy efficiency, and, more controversially, nuclear power. To reduce coal’s 

contribution to global warming, we must deploy and improve systems that will keep 

the carbon in coal out of the atmosphere, specifically systems that capture carbon 

dioxide (CO2) from coal-fired power plants and other industrial sources for safe and 

effective disposal in geologic formations. 

The Toll From Coal 

Before turning to the status of CCD let me say a few words about coal use generally. The role of coal now and in the future is controversial due to the damages 

38 

its production and use inflict today and skepticism that those damages can or will 

be reduced to a point where we should continue to rely on it as a mainstay of industrial economies. Coal is cheap and abundant compared to oil and natural gas. But 

the toll from coal as it is used today is enormous. From mining deaths and illness 

and devastated mountains and streams from practices like mountain top removal 

mining, to accidents at coal train crossings, to air emissions of acidic, toxic, and 

heat-trapping pollution from coal combustion, to water pollution from coal mining 

and combustion wastes, the conventional coal fuel cycle is among the most environmentally destructive activities on Earth. Certain coal production processes are inherently harmful and while our society has the capacity to reduce many of today’s 

damages, to date, we have not done so adequately nor have we committed to doing 

so. These failures have created well-justified opposition by many people to continued 

or increased dependence on coal to meet our energy needs. 

Our progress of reducing harms from mining, transport, and use of coal has been 

frustratingly slow and an enormous amount remains to be done. Today mountain 

tops in Appalachia are destroyed to get at the coal underneath and rocks, soil, debris, and waste products are dumped into valleys and streams, destroying them as 

well. Waste impoundments loom above communities (including, in one particularly 

egregious case, above an elementary school) and thousands of miles of streams are 

polluted. In other areas surface mine reclamation is incomplete, inadequately performed and poorly supervised due to regulatory gaps and poorly funded regulatory 

agencies. 

In the area of air pollution, although we have technologies to dramatically cut 

conventional pollutants from coal-fired power plants, in 2004 only one-third of U.S. 

coal capacity was equipped with scrubbers for sulfur dioxide control and even less 

capacity applied selective catalytic reduction (SCR) for nitrogen oxides control. And 

under the Administration’s so-called CAIR rule, even in 2020 nearly 30 percent of 

coal capacity will still not employ scrubbers and nearly 45 percent will lack SCR 

equipment. Moreover, because this administration has deliberately refused to require use of available highly effective control technologies for the brain poison mercury, we will suffer decades more of cumulative dumping of this toxin into the air 

at rates several times higher than is necessary or than faithful implementation of 

the Clean Air Act would achieve. Finally, there are no controls in place for CO2, the 

global warming pollutant emitted by the more than 330,000 megawatts of coal-fired 

plants; nor are there any CO2 control requirements adopted today for old or new 

plants save in California. 

Mr. Chairman and members of the Committee, the environmental community has 

been criticized in some quarters for our generally negative view regarding coal as 

an energy resource. But consider the reasons for this. Our community reacts to the 

facts on the ground and those facts are far from what they should be if coal is to 

play a role as a responsible part of the 21st century energy mix. Rather than simply 

decrying the attitudes of those who question whether using large amounts of coal 

can and will be carried out in a responsible manner, the coal industry in particular 

should support policies to correct today’s abuses and then implement those reforms. 

Were the industry to do this, there would be real reasons for my community and 

other critics of coal to consider whether their positions should be reconsidered. 

The Need for CCD 

Turning to CCD, NRDC supports rapid deployment of such capture and disposal 

systems for sources using coal. Such support is not a statement about how dependent the U.S. or the world should be on coal and for how long. Any significant additional use of coal that vents its CO2 to the air is fundamentally in conflict with the 

need to keep atmospheric concentrations of CO2 from rising to levels that will 

produce dangerous disruption of the climate system. Given that an immediate 

world-wide halt to coal use is not plausible, analysts and advocates with a broad 

range of views on coal’s role should be able to agree that, if it is safe and effective, 

CCD should be rapidly deployed to minimize CO2 emissions from the coal that we 

do use. 

Today coal use and climate protection are on a collision course. Without rapid deployment of CCD systems, that collision will occur quickly and with spectacularly 

bad results. The very attribute of coal that has made it so attractive—its abundance—magnifies the problem we face and requires us to act now, not a decade from 

now. Until now, coal’s abundance has been an economic boon. But today, coal’s 

abundance, absent corrective action, is more bane than boon. 

Since the dawn of the industrial age, human use of coal has released about 150 

billion metric tons of carbon into the atmosphere—about half the total carbon emissions due to fossil fuel use in human history. But that contribution is the tip of the 

carbon iceberg. Another 4 trillion metric tons of carbon are contained in the remainVerDate Nov 24 2008 13:10 May 24, 2012 Jkt 074322 PO 00000 Frm 00042 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\74322.TXT SCOM1 PsN: JACKIE
39 

ing global coal resources. That is a carbon pool nearly seven times greater than the 

amount in our pre-industrial atmosphere. Using that coal without capturing and 

disposing of its carbon means a climate catastrophe. 

And the die is being cast for that catastrophe today, not decades from now. Decisions being made today in corporate board rooms, government ministries, and Congressional hearing rooms are determining how the next coal-fired power plants will 

be designed and operated. Power plant investments are enormous in scale, more 

than $1 billion per plant, and plants built today will operate for 60 years or more. 

The International Energy Agency (IEA) forecasts that more than $5 trillion will be 

spent globally on new power plants in the next 25 years. Under IEA’s forecasts, over 

1,800 gigawatts (GW) of new coal plants will be built between now and 2030—capacity equivalent to 3,000 large coal plants, or an average of ten new coal plants every 

month for the next quarter century. This new capacity amounts to 1.5 times the 

total of all the coal plants operating in the world today. 

The astounding fact is that under IEA’s forecast, 7 out of every 10 coal plants that 

will be operating in 2030 don’t exist today. That fact presents a huge opportunity— 

many of these coal plants will not need to be built if we invest more in efficiency; 

additional numbers of these coal plants can be replaced with clean, renewable alternative power sources; and for the remainder, we can build them to capture their 

CO2, instead of building them the way our grandfathers built them. 

If we decide to do it, the world could build and operate new coal plants so that 

their CO2 is returned to the ground rather than polluting the atmosphere. But we 

are losing that opportunity with every month of delay—10 coal plants were built the 

old-fashioned way last month somewhere in the world and 10 more old-style plants 

will be built this month, and the next and the next. Worse still, with current policies 

in place, none of the 3,000 new plants projected by IEA are likely to capture their 

CO2. 

Each new coal plant that is built carries with it a huge stream of CO2 emissions 

that will likely flow for the life of the plant—60 years or more. Suggestions that 

such plants might be equipped with CO2 capture devices later in life might come 

true but there is little reason to count on it. As I will discuss further in a moment, 

while commercial technologies exist for pre-combustion capture from gasificationbased power plants, most new plants are not using gasification designs and the few 

that are, are not incorporating capture systems. Installing capture equipment at 

these new plants after the fact is implausible for traditional coal plant designs and 

expensive for gasification processes. 

If all 3,000 of the next wave of coal plants are built with no CO2 controls, their 

lifetime emissions will impose an enormous pollution lien on our children and 

grandchildren. Over a projected 60-year life these plants would likely emit 750 billion tons of CO2, a total, from just 25 years of investment decisions, that is 30 percent greater than the total CO2 emissions from all previous human use of coal. Once 

emitted, this CO2 pollution load remains in the atmosphere for centuries. Half of 

the CO2 emitted during World War I remains in the atmosphere today. 

In short, we face an onrushing train of new coal plants with impacts that must 

be diverted without delay. What can the U.S. do to help? The U.S. is forecasted to 

build nearly 300 of these coal plants, according to reports and forecasts published 

by the U.S. EIA. We should adopt a national policy that new coal plants be required 

to employ CCD without delay. By taking action ourselves, we can speed the deployment of CCD here at home and set an example of leadership. That leadership will 

bring us economic rewards in the new business opportunities it creates here and 

abroad and it will speed engagement by critical countries like China and India. 

To date our efforts have been limited to funding research, development, and limited demonstrations. Such funding can help in this effort if it is wisely invested. But 

government subsidies—which are what we are talking about—cannot substitute for 

the driver that a real market for low-carbon goods and services provides. That market will be created only when requirements to limit CO2 emissions are adopted. In 

this Congress serious attention is finally being directed to enactment of such measures. 

Key Questions About CCD 

I started studying CCD in detail 10 years ago and the questions I had then are 

those asked today by people new to the subject. Do reliable systems exist to capture 

CO2 from power plants and other industrial sources? Where can we put CO2 after 

we have captured it? Will the CO2 stay where we put it or will it leak? How much 

disposal capacity is there? Are CCD systems ‘‘affordable’’? To answer these questions, the Intergovernmental Panel on Climate Change (IPCC) decided 4 years ago 

to prepare a special report on the subject. That report was issued in September 2005 

40 

as the IPCC Special Report on Carbon Dioxide Capture and Storage. I was privileged to serve as a review editor for the report’s chapter on geologic storage of CO2. 

CO2 Capture 

The IPCC special report groups capture or separation of CO2 from industrial 

gases into four categories: post-combustion; pre-combustion; oxyfuel combustion; and 

industrial separation. I will say a few words about the basics and status of each 

of these approaches. In a conventional pulverized coal power plant, the coal is combusted using normal air at atmospheric pressures. This combustion process produces a large volume of exhaust gas that contains CO2 in large amounts but in low 

concentrations and low pressures. Commercial post-combustion systems exist to capture CO2 from such exhaust gases using chemical ‘‘stripping’’ compounds and they 

have been applied to very small portions of flue gases (tens of thousands of tons 

from plants that emit several million tons of CO2 annually) from a few coal-fired 

power plants in the U.S. that sell the captured CO2 to the food and beverage industry. However, industry analysts state that today’s systems, based on publicly available information, involve much higher costs and energy penalties than the principal 

demonstrated alternative, pre-combustion capture. 

New and potentially less expensive post-combustion concepts have been evaluated 

in laboratory tests and some, like ammonia-based capture systems, are scheduled 

for small pilot-scale tests in the next few years. Under normal industrial development scenarios, if successful such pilot tests would be followed by larger demonstration tests and then by commercial-scale tests. These and other approaches should 

continue to be explored. However, unless accelerated by a combination of policies, 

subsidies, and willingness to take increased technical risks, such a development program could take one or two decades before post-combustion systems would be accepted for broad commercial application. 

Pre-combustion capture is applied to coal conversion processes that gasify coal 

rather than combust it in air. In the oxygen-blown gasification process coal is heated 

under pressure with a mixture of pure oxygen, producing an energy-rich gas stream 

consisting mostly of hydrogen and carbon monoxide. Coal gasification is widely used 

in industrial processes, such as ammonia and fertilizer production around the world. 

Hundreds of such industrial gasifiers are in operation today. In power generation 

applications as practiced today this ‘‘syngas’’ stream is cleaned of impurities and 

then burned in a combustion turbine to make electricity in a process known as Integrated Gasification Combined Cycle or IGCC. In the power generation business, 

IGCC is a relatively recent development—about two decades old and is still not 

widely deployed. There are two IGCC power-only plants operating in the U.S. today 

and about 14 commercial IGCC plants are operating, with most of the capacity in 

Europe. In early years of operation for power applications a number of IGCC 

projects encountered availability problems but those issues appear to be resolved 

today, with Tampa Electric Company reporting that its IGCC plant in Florida is the 

most dispatched and most economic unit in its generating system. 

Commercially demonstrated systems for pre-combustion capture from the coal 

gasification process involve treating the syngas to form a mixture of hydrogen and 

CO2 and then separating the CO2, primarily through the use of solvents. These 

same techniques are used in industrial plants to separate CO2 from natural gas and 

to make chemicals such as ammonia out of gasified coal. However, because CO2 can 

be released to the air in unlimited amounts under today’s laws, except in niche applications, even plants that separate CO2 do not capture it; rather they release it 

to the atmosphere. Notable exceptions include the Dakota Gasification Company 

plant in Beulah, North Dakota, which captures and pipelines more than one million 

tons of CO2 per year from its lignite gasification plant to an oil field in Saskatchewan, and ExxonMobil’s Shute Creek natural gas processing plant in Wyoming, 

which strips CO2 from sour gas and pipelines several million tons per year to oil 

fields in Colorado and Wyoming. 

Today’s pre-combustion capture approach is not applicable to the installed base 

of conventional pulverized coal in the U.S. and elsewhere. However, it is ready today 

for use with IGCC power plants. The oil giant BP has announced an IGCC project 

with pre-combustion CO2 capture at a site in California. When operational the 

project will gasify petroleum coke, a solid fuel that resembles coal more than petroleum to make electricity for sale to the grid. The captured CO2 will be sold to an 

oil field operator in California to enhance oil recovery. The principal obstacle for 

broad application of pre-combustion capture to new power plants is not technical, 

it is economic: under today’s laws it is cheaper to release CO2 to the air rather than 

capturing it. Enacting laws to limit CO2 pollution can change this situation, as I 

discuss later. 

41 

While pre-combustion capture from IGCC plants is the approach that is ready 

today for commercial application, it is not the only method for CO2 capture that may 

emerge if laws creating a market for CO2 capture are adopted. I have previously 

mentioned post-combustion techniques now being explored. Another approach, 

known as oxyfuel combustion, is also in the early stages of research and development. In the oxyfuel process, coal is burned in oxygen rather than air and the exhaust gases are recycled to build up CO2 concentrations to a point where separation 

at reasonable cost and energy penalties may be feasible. Small scale pilot studies 

for oxyfuel processes have been announced. As with post-combustion processes, absent an accelerated effort to leapfrog the normal commercialization process, it could 

be one or two decades before such systems might begin to be deployed broadly in 

commercial application. 

Given the massive amount of new coal capacity scheduled for construction in the 

next two decades, we cannot afford to wait until we see if these alternative capture 

systems prove out, nor do we need to. Coal plants in the design process today can 

employ proven IGCC and precombustion capture systems to reduce their CO2 emissions by about 90 percent. Adoption of policies that set a CO2 performance standard 

now for such new plants will not anoint IGCC as the technological winner since alternative approaches can be employed when they are ready. If the alternatives 

prove superior to IGCC and pre-combustion capture, the market will reward them 

accordingly. As I will discuss later, adoption of CO2 performance standards is a critical step to improve today’s capture methods and to stimulate development of competing systems. 

I would like to say a few words about so-called ‘‘capture-ready’’ or ‘‘capture-capable’’ coal plants. Some years ago I was under the impression that some technologies 

like IGCC, initially built without capture equipment could be properly called ‘‘capture-ready.’’ However, the implications of the rapid build-out of new coal plants for 

global warming and many conversations with engineers since then have educated 

me to a different view. Unfortunately, the term ‘‘capture-ready’’ has been embraced 

by industry lobbyists in a manner that strips the concept of any meaning. According 

to some industry representatives, a power plant that simply leaves physical space 

for an unidentified black box deserves to be called ‘‘capture-ready.’’ If that makes 

a power plant ‘‘capture-ready’’ Mr. Chairman, then my driveway is ‘‘Ferrari-ready.’’ 

We should not be investing today in coal plants at more than a billion dollars apiece 

with nothing more than a hope that some kind of capture system will turn up. We 

would not get on a plane to a destination if the pilot told us there was no landing 

site but options were being researched. 

It is correct that an IGCC unit built without capture equipment can be equipped 

later with such equipment and at much lower cost than attempting to retrofit a conventional pulverized coal plant with today’s demonstrated post-combustion systems. 

However, the costs and engineering reconfigurations of such an approach are substantial. More importantly, we need to begin capturing CO2 from new coal plants 

without delay in order to keep global warming from becoming a potentially runaway 

problem. Given the pace of new coal investments in the U.S. and globally, we simply 

do not have the time to build a coal plant today and think about capturing its CO2

down the road. 

Geologic Disposal 

We have a significant experience base for injecting large amounts of CO2 into geologic formations. For several decades oil field operators have received high pressure 

CO2 for injection into fields to enhance oil recovery, delivered by pipelines spanning 

as much as several hundred miles. Today in the U.S. a total of more than 35 million 

tons of CO2 are injected annually in more than 70 projects. (Unfortunately, due to 

the lack of any controls on CO2 emissions, about 80 percent of that CO2 comes from 

natural CO2 formations rather than captured from industrial sources. Historians 

will marvel that we persisted so long in pulling CO2 out of holes in the ground in 

order to move it hundreds of miles and stick in back in holes at the same time we 

were recognizing the harm being caused by emissions of the same molecule from 

nearby large industrial sources.) In addition to this enhanced oil recovery experience, there are several other large injection projects in operation or announced. The 

longest running of these, the Sleipner project, began in 1996. 

But the largest of these projects injects on the order of one million tons per year 

of CO2, while a single large coal power plant can produce about five million tons 

per year. And of course, our experience with man-made injection projects does not 

extend for the thousand year or more period that we would need to keep CO2 in 

place underground for it to be effective in helping to avoid dangerous global warming. Accordingly, the public and interested members of the environmental, industry 

42 

and policy communities rightly ask whether we can carry out a large scale injection 

program safely and assure that the injected CO2 will stay where we put it. 

Let me summarize the findings of the IPCC on the issues of safety and efficacy 

of CCD. In its 2005 report the IPCC concluded the following with respect to the 

question of whether we can safely carry out carbon injection operations on the required scale: 

‘‘With appropriate site selection based on available subsurface information, a 

monitoring programme to detect problems, a regulatory system and the appropriate use of remediation methods to stop or control CO2 releases if they arise, 

the local health, safety and environment risks of geological storage would be 

comparable to the risks of current activities such as natural gas storage, EOR 

and deep underground disposal of acid gas.’’ 

The knowledge exists to fulfill all of the conditions the IPCC identifies as needed 

to assure safety. While EPA has authority regulate large scale CO2 injection projects 

its current underground injection control regulations are not designed to require the 

appropriate showings for permitting a facility intended for long-term retention of 

large amounts of CO2. With adequate resources applied, EPA should be able to 

adopt the necessary revisions to its rules in one to 2 years. While EPA has announced its intention to issue a proposed rule this year, intense oversight by Congress is likely to be needed to assure this happens. 

Do we have a basis today for concluding that injected CO2 will stay in place for 

the long periods required to prevent its contributing to global warming? The IPCC 

report concluded that we do, stating: 

‘‘Observations from engineered and natural analogues as well as models suggest 

that the fraction retained in appropriately selected and managed geological reservoirs is very likely to exceed 99 percent over 100 years and is likely to exceed 

99 percent over 1,000 years.’’ 

Despite this conclusion by recognized experts there is still reason to ask what are 

the implications of imperfect execution of large scale injection projects, especially in 

the early years before we have amassed more experience? Is this reason enough to 

delay application of CO2 capture systems to new power plants until we gain such 

experience from an initial round of multi-million ton ‘‘demonstration’’ projects? To 

sketch an answer to this question, my colleague Stefan Bachu, a geologist with the 

Alberta Energy and Utilities Board, and I wrote a paper for the Eighth International Conference on Greenhouse Gas Control Technologies in June 2006. The obvious and fundamental point we made is that without CO2 capture, new coal plants 

built during any ‘‘delay and research’’ period will put 100 percent of their CO2 into 

the air and may do so for their operating life if they were ‘‘grandfathered’’ from retrofit requirements. Those releases need to be compared to hypothetical leaks from 

early injection sites. 

Our conclusions were that even with extreme, unrealistically high hypothetical 

leakage rates from early injection sites (10 percent per year), a long period to leak 

detection (5 years) and a prolonged period to correct the leak (1 year), a policy that 

delayed installation of CO2 capture at new coal plants to await further research 

would result in cumulative CO2 releases twenty times greater than from the hypothetical faulty injectionsites, if power plants built during the research period were 

‘‘grandfathered’’ from retrofit requirements. If this wave of new coal plants were all 

required to retrofit CO2 capture by no later than 2030, the cumulative emissions 

would still be four times greater than under the no delay scenario. I believe that 

any objective assessment will conclude that allowing new coal plants to be built 

without CO2 capture equipment on the ground that we need more large scale injection experience will always result in significantly greater CO2 releases than starting 

CO2 capture without delay for new coal plants now being designed. 

The IPCC also made estimates about global storage capacity for CO2 in geologic 

formations. It concluded as follows: 

‘‘Available evidence suggests that, worldwide, it is likely that there is a technical potential of at least about 2,000 GtCO2 (545 GtC) of storage capacity in 

geological formations. There could be a much larger potential for geological storage in saline formations, but the upper limit estimates are uncertain due to lack 

of information and an agreed methodology.’’ 

Current CO2 emissions from the world’s power plants are about 10 Gt (billion 

metric tons) per year, so the IPCC estimate indicates 200 years of capacity if power 

plant emissions did not increase and 100 years capacity if annual emissions doubled. 

43 

Policy Actions to Speed CCD 

As I stated earlier, research and development funding is useful but it cannot substitute for the incentive that a genuine commercial market for CO2 capture and disposal systems will provide to the private sector. The amounts of capital that the private sector can spend to optimize CCD methods will almost certainly always dwarf 

what Congress will provide with taxpayer dollars. To mobilize those private sector 

dollars, Congress needs a stimulus more compelling than the offer of modest handouts for research. Congress has a model that works: intelligently designed policies 

to limit emissions cause firms to spend money finding better and less expensive 

ways to prevent or capture emissions. 

Where a technology is already competitive with other emission control techniques, 

for example, sulfur dioxide scrubbers, a cap and trade program like that enacted by 

Congress in 1990, can result in more rapid deployment, improvements in performance, and reductions in costs. Today’s scrubbers are much more effective and much 

less costly than those built in the 1980s. 

However, a CO2 cap and trade program by itself may not result in deployment 

of CCD systems as rapidly as we need. Many new coal plant design decisions are 

being made literally today. Depending on the pace of required reductions under a 

global warming bill, a firm may decide to build a conventional coal plant and purchase credits from the cap and trade market rather than applying CCD systems to 

the plant. While this may appear to be economically rational in the short term, it 

is likely to lead to higher costs of CO2 control in the mid and longer term if substantial amounts of new conventional coal construction leads to ballooning demand for 

CO2 credits. Recall that in the late 1990s and the first few years of this century, 

individual firms thought it made economic sense to build large numbers of new gasfired power plants. The problem is too many of them had the same idea and the 

resulting increase in demand for natural gas increased both the price and volatility 

of natural gas to the point where many of these investments are idle today. 

Moreover, delaying the start of CCD until a cap and trade system price is high 

enough to produce these investments delays the broad demonstration of the technology that the U.S. and other countries will need if we continue substantial use 

of coal as seem likely. The more affordable CCD becomes, the more widespread its 

use will be throughout the world, including in rapidly growing economies like China 

and India. But the learning and cost reductions for CCD that are desirable will 

come only from the experience gained by building and operating the initial commercial plants. The longer we wait to ramp up this experience, the longer we will wait 

to see CCD deployed here and in countries like China. 

Accordingly, we believe the best policy package is a hybrid program that combines 

the breadth and flexibility of a cap and trade program with well-designed performance measures focused on key technologies like CCD. One such performance measure is a CO2 emissions standard that applies to new power investments. California 

enacted such a measure in S.B. 1368 last year. It requires new investments for sale 

of power in California to meet a performance standard that is achievable by coal 

with a moderate amount of CO2 capture. 

Another approach is a low-carbon generation obligation for coal-based power. 

Similar in concept to a renewable performance standard, the low-carbon generation 

obligation requires an initially small fraction of sales from coal-based power to meet 

a CO2 performance standard that is achievable with CCD. The required fraction of 

sales would increase gradually over time and the obligation would be tradable. 

Thus, a coal-based generating firm could meet the requirement by building a plant 

with CCD, by purchasing power generated by another source that meets the standard, or by purchasing credits from those who build such plants. This approach has 

the advantage of speeding the deployment of CCD while avoiding the ‘‘first mover 

penalty.’’ Instead of causing the first builder of a commercial coal plant with CCD 

to bear all of the incremental costs, the tradable low-carbon generation obligation 

would spread those costs over the entire coal-based generation system. The builder 

of the first unit would achieve far more hours of low-carbon generation than required and would sell the credits to other firms that needed credits to comply. These 

credit sales would finance the incremental costs of these early units. This approach 

provides the coal-based power industry with the experience with a technology that 

it knows is needed to reconcile coal use and climate protection and does it without 

sticker shock. 

A bill introduced last year, S. 309, contains such a provision. It begins with a requirement that one-half of one per cent of coal-based power sales must meet the 

low-carbon performance standard starting in 2015 and the required percentage increases over time according to a statutory minimum schedule that can be increased 

in specified amounts by additional regulatory action. 

44 

A word about costs is in order. With today’s off the shelf systems, estimates are 

that the production cost of electricity at a coal plant with CCD could be as much 

as 40 percent higher than at a conventional plant that emits its CO2. But the impact on average electricity prices of introducing CCD now will be very much smaller 

due to several factors. First, power production costs represent about 60 percent of 

the price you and I pay for electricity; the rest comes from transmission and distribution costs. Second, coal-based power represents just over half of U.S. power consumption. Third, and most important, even if we start now, CCD would be applied 

to only a small fraction of U.S. coal capacity for some time. Thus, with the trading 

approach I have outlined, the incremental costs on the units equipped with CCD 

would be spread over the entire coal-based power sector or possibly across all fossil 

capacity depending on the choices made by Congress. Based on CCD costs available 

in 2005 we estimate that a low-carbon generation obligation large enough to cover 

all forecasted new U.S. coal capacity through 2020 could be implemented for about 

a two per cent increase in average U.S. retail electricity rates. 

Recent Congressional Action 

Title VII of the Energy Independence and Security Act of 2007 (EISA) contains 

some provisions that, if funded, will help to make CCD a reality. These include authorizations to conduct at least seven large-scale geologic sequestration projects and 

separate authorizations for projects for large-scale capture of CO2 from industrial 

sources. A third provision requires the U.S. Geological Survey to carry out a comprehensive assessment of capacity for geologic disposal of CO2. 

NRDC supports implementation of these provisions but we urge that they be complemented with enactment this year of a comprehensive program to cap CO2 and 

other greenhouse gases, along with complementary policies to accelerate CCD deployment. Enacting such a cap and trade bill will demonstrate the policy resolve to 

shift to lower-emitting energy investments, including CCD. That will help ensure 

that the demonstrations called for in EISA are integrated with commercial energy 

investments rather than being carried out with a science experiment mentality. It 

will also spur much more cost-effective cost-sharing arrangements with industry 

since these projects will help industry participants meet their obligations under a 

cap and trade program. As is shown by legislation like the Lieberman-Warner Climate Security Act, S. 2191, such comprehensive legislation can provide much larger 

resources to promote early CCD projects than the amounts authorized by EISA, 

even if the EISA funds were fully appropriated. 

NRDC believes that the large-scale projects in EISA should be implemented as 

an integral component of a policy to move forward with near-term deployment of 

CCD. New coal-fired power plants continue to be proposed in the U.S. and it is essential that any such plants should employ CCD. EISA’s large-scale injection 

projects can serve as repositories for the CO2 produced by such plants. Thus, these 

projects should not be thought of as short-term operations that will be operated for 

a few years and then shut down. Any early ‘‘demonstration’’ projects should be permitted by EPA for operation as permanent repositories. Such projects also should 

use anthropogenic CO2, as opposed to the use of naturally occurring or recycled CO2

used in most enhanced oil recovery projects today. 

Finally, I want to repeat the importance of prompt adoption of permitting and 

operational requirements for CO2 disposal by EPA. While EPA has announced an 

intention to propose rules this year, we encourage this Committee to work with the 

Environment and Public Works and the Appropriations Committees to assure that 

EPA adopts final rules in an expeditious manner. 

Conclusions 

To sum up, since we will almost certainly continue using large amounts of coal 

in the U.S. and globally in the coming decades, it is imperative that we act now 

to deploy CCD systems. Commercially demonstrated CO2 capture systems exist 

today and competing systems are being researched. Improvements in current systems and emergence of new approaches will be accelerated by requirements to limit 

CO2 emissions. Commercial deployment of such systems will only happen with enactment of comprehensive climate bills that cap CO2 and incorporate complementary 

policies to promote accelerated deployment of CCD. Geologic disposal of large 

amounts of CO2 is viable and we know enough today to conclude that it can be done 

safely and effectively. EPA must act without delay to revise its regulations to provide the necessary framework for efficient permitting, monitoring and operational 

practices for large scale permanent CO2 repositories. 

Finally CCD is an important strategy to reduce CO2 emissions from fossil fuel use 

but it is not the basis for a climate protection program by itself. Increased reliance 

on low-carbon energy resources is the key to protecting the climate. The lowest carVerDate Nov 24 2008 13:10 May 24, 2012 Jkt 074322 PO 00000 Frm 00048 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\74322.TXT SCOM1 PsN: JACKIE
45 

bon resource of all is smarter use of energy; energy efficiency investments will be 

the backbone of any sensible climate protection strategy. Renewable energy will 

need to assume a much greater role than it does today. With today’s use of solar, 

wind and biomass energy, we tap only a tiny fraction of the energy the sun provides 

every day. There is enormous potential to expand our reliance on these resources. 

We have no time to lose to begin cutting global warming emissions. Fortunately, we 

have technologies ready for use today that can get us started. 

Mr. Chairman, that completes my testimony, I will be happy to take any questions you or other committee members may have. 

Senator KERRY. Well, thank you, Mr. Hawkins. 

I, personally, couldn’t agree with you more, but we’ll talk about 

that a lot more in a second. 

Mr. Novak? 

STATEMENT OF JOHN NOVAK, EXECUTIVE DIRECTOR, 

FEDERAL AND INDUSTRY ACTIVITIES, ENVIRONMENT AND 

GENERATION, ELECTRIC POWER RESEARCH INSTITUTE 

Mr. NOVAK. Good afternoon, Chairman Kerry, Ranking Member 

Ensign, and Senator Stevens. 

I’m John Novak, Executive Director of Federal and Industry activities at the Electric Power Research Institute and as I hope you 

know, EPRI conducts research and development on technology, operations and the environment, for the global electric power industry. 

As Senator Kerry mentioned, last November my colleague, Dr. 

Bryan Hannegan testified before this committee, this Subcommittee, about our PRISM and MERGE analyses. These analyses show the need for, and the value of, having a full portfolio of 

technologies, including end- use energy efficiency, renewable nuclear power, advanced coal with CO2 capture and storage, and 

plug-in hybrid electric vehicles in order to meet future electricity 

demand, and to meet global climate change goals. 

As EPRI’s President, Steve Specker, has said on numerous occasions about technologies, ‘‘We need them all.’’ 

Information on the PRISM/MERGE analysis can be found in a 

recent, the Fall issue of our EPRI journal, and I’ve provided copies 

for the Subcommittee. One fundamental implication of our work is 

very clear—we must move from analysis to action if we are to deploy this full portfolio of technologies in a timely and effective manner. For coal, this implies a full portfolio of coal technologies. 

We’re talking about IGCC, IGCC—particularly when you plan to 

capture and store CO2—has some advantages over traditional pulverized coal. But today’s IGCC designs have some disadvantages, 

as well. 

EPRI’s Coalfleet for Tomorrow program has identified the 

RD&D pathways to demonstrate, by 2025, a full portfolio of economically attractive, commercial-scale, advanced coal-powered integrated CO2 capture and storage technologies suitable for use within 

the broad range of U.S. coal types, and information on that pathway is included in my testimony. 

The key to proving CO2 capture and storage capability is a demonstration of CO2 capture and storage at large scale—at IGCC, for 

pulverized coal and for oxy-combustion—the storage of the CO2 in 

a variety of geologies. Large, combined capture and storage demVerDate Nov 24 2008 13:10 May 24, 2012 Jkt 074322 PO 00000 Frm 00049 Fmt 6633 Sfmt 6601 S:\GPO\DOCS\74322.TXT SCOM1 PsN: JACKIE
46 

onstrations should be encouraged in different regions, and with different coals and technologies. 

To help move from analysis to action, EPRI has identified a number of demonstration projects that target critical gaps, that must 

be achieved to achieve this full portfolio of technologies. 

Five of the critical projects are aimed at demonstrating the effectiveness, and reducing the cost, of CO2 capture and storage from 

coal plants. These five coal projects include two projects for demonstrating different post-combustion CO2 capture technologies with 

storage, one with American Electric Power and one with the Southern company—it includes a project to demonstrate IGCC operation 

with integrated CO2 capture and storage, a high-efficiency pulverized coal plant with state-of-the-art emissions controls, and integrated CO2 capture and storage—we call that our UltraGen 

project—and the demonstration of a key enabling technology to 

lower the cost of oxygen production for IGCC and oxy-combustion 

plants. 

These projects are designed to compliment ongoing private and 

government sector activities. All of these critical demonstration 

projects were identified through EPRI’s collaborative process, and 

we expect to participate in each of them. But they are electricitysector projects, not EPRI projects. Each will require a consortium 

of companies, drawing on both private sector and government funding, as appropriate for each project. 

EPRI and its members are further evaluating these projects and, 

in some cases, are already moving forward on a plan to fund and 

implement each project. 

EPRI appreciates the opportunity to provide testimony to the 

Subcommittee on this important topic, and I would be happy to answer any questions. 

Thank you. 

[The prepared statement of Mr. Novak follows:] 

PREPARED STATEMENT OF JOHN NOVAK, EXECUTIVE DIRECTOR, FEDERAL AND

INDUSTRY ACTIVITIES, ENVIRONMENT AND GENERATION, ELECTRIC POWER

RESEARCH INSTITUTE

Introduction 

Thank you, Mr. Chairman, Ranking Member Ensign, and Members of the Subcommittee. I am John Novak, Executive Director of Federal and Industry Activities 

for the Environment and Generation Sectors of the Electric Power Research Institute (EPRI). EPRI conducts research and development on technology, operations and 

the environment for the global electric power industry. As an independent, non-profit Institute, EPRI brings together its members, scientists and engineers, along with 

experts from academia, industry and other centers of research to: 

• collaborate in solving challenges in electricity generation, delivery and use; 

• provide technological, policy and economic analyses to drive long-range research 

and development planning; and 

• support multi-discipline research in emerging technologies and issues. 

EPRI’s members represent more than 90 percent of the electricity generated in 

the United States, and international participation extends to 40 countries. EPRI has 

major offices and laboratories in Palo Alto, California; Charlotte, North Carolina; 

Knoxville, Tennessee, and Lenox, Massachusetts. 

EPRI appreciates the opportunity to provide testimony to the Subcommittee on 

the topic of integrated gasification combined cycle (IGCC) technologies and the need 

for large scale IGCC demonstration projects that feature CO2 capture and sequestration. 

47 

1Feasibility Study for an Integrated Gasification Combined Cycle Facility at a Texas Site, 

EPRI report 1014510, October 2006. 

Integrated Gasification Combined Cycle (IGCC) 

In integrated gasification combined cycle plants, coal or petroleum coke is partially oxidized with oxygen to CO and hydrogen, the impurities cleansed in an acid 

gas removal process and the clean gas (called ‘‘syngas’’) burned in a combined cycle 

to produce electricity. The energy use in the cycle is integrated between the gasification section and the power block, hence the name. 

There are only six IGCC plants in the world operating on coal. These operating 

units also use petroleum coke or blends due to its lower price. One, the Vresova 

IGCC based in the Czech Republic (Lurgi-type gasifier) is 350 MW. The others are 

each about 250 MW. The two in the United States are Wabash (Conoco Phillips 

gasifier) and Polk (GE gasifier) in Indiana and Florida. Two additional IGCCs in 

Europe are Buggenum, Netherlands and Puertollano, Spain (both variations on the 

Shell gasifier). A new IGCC started operation this year at Nakoso, Japan (MHI gasifier). Chemical plants around the world have accumulated a 100-year experience 

base operating coal-based gasification units and related gas cleanup processes. The 

most advanced of these units are similar to the front end of a modern IGCC facility. 

Similarly, several decades of experience firing natural gas and petroleum distillate 

have established a high level of maturity for the basic combined cycle generating 

technology. 

IGCC technology is still relatively new and needs more commercial installations. 

Based on the limited data available, today’s IGCC plants are available 5–7 percent 

fewer hours per year than conventional pulverized coal (PC) plants. While it is likely that IGCC will ‘‘catch up’’ with PC, the initial learning curve on all IGCCs to 

date has been slow. Better designs, models, incorporation of lessons learned would 

all help. Ongoing RD&D continues to provide significant advances in the base technologies, as well as in the suite of technologies used to integrate them into an IGCC 

generating facility. 

The emissions of air pollutants and greenhouse gases from an IGCC are less than 

a conventional pulverized coal plant (though latest designs make this difference 

smaller). The IGCC design uses less water than a conventional coal plant since a 

great deal of power comes from the gas turbine. The pre-cleaning of primary pollutants prior to combustion in the gas turbine allows possible later capture of CO2 from 

a concentrated high-pressure gas requiring relatively low energy use. 

IGCC plants (like PC plants) do not capture CO2 without substantial plant modifications, energy losses, and investments in additional process equipment. No one 

is currently capturing CO2 at full scale from IGCC plants that generate electricity 

from coal. CO2 separation processes suitable for IGCC plants are used commercially 

in the oil and gas and chemical industries at a scale close to that ultimately needed, 

but their application requires the addition of more processing equipment to an IGCC 

plant and the deployment of gas turbines that can burn nearly pure hydrogen. 

The electricity cost premium for including CO2 capture in IGCC plants, along with 

drying, compression, transportation, and storage, is about 40–50 percent. Although 

this is a lower cost increase in percentage terms than that for conventional PC 

plants, IGCC plants initially cost more than PC plants. Thus, the bottom-line cost 

to consumers for power from IGCC plants with capture using today’s technology is 

likely to be comparable to that for PC plants with capture (the actual relative competitiveness depends on coal moisture content and other factors as described below). 

However, the magnitude of these impacts could likely be reduced substantially 

through aggressive investments in R&D. 

The CO2 capture cost premiums listed above vary in real-world applications, depending on available coals and their physical-chemical properties, desired plant size, 

the CO2 capture process and its degree of integration with other plant processes, 

plant elevation, the value of plant co-products, and other factors. Nonetheless, IGCC 

with CO2 capture generally shows an economic advantage in studies based on lowmoisture bituminous coals. For coals with high moisture and low heating value, 

such as subbituminous and lignite coals, an EPRI study shows PC with CO2 capture 

being competitive with or having an advantage over IGCC.1 EPRI stresses that no 

single advanced coal generating technology (or any generating technology) has clearcut economic advantages across the range of U.S. applications. The best strategy for 

meeting future electricity needs in an economic and environmentally sustainable 

way lies in developing multiple technologies from which power producers (and their 

regulators) can choose the one best suited to local conditions and preferences. EPRI 

strongly recommends that policies reflect a portfolio approach that enables commercial incorporation of CCS into multiple advanced coal power technologies. 

48 

The key to proving CCS capability is the demonstration of CCS at large-scale (on 

the order of 1 million tons CO2/year) for both pre- and post-combustion capture with 

storage in a variety of geologies. Large combined capture and storage demonstrations should be encouraged in different regions and with different coals and technologies. 

Advanced Coal Generation With CO2 Capture and Storage 

Through the development and deployment of advanced coal plants with integrated 

CO2 capture and storage (CCS) technologies, coal power can become part of the solution to satisfying both our energy needs and our global climate change concerns. 

However, a sustained RD&D program at heightened levels of investment and the 

resolution of legal and regulatory unknowns for long-term geologic CO2 storage will 

be required to achieve the promise of advanced coal with CCS technologies. The 

members of EPRI’s CoalFleet for Tomorrow program—a research collaborative 

comprising more than 60 organizations representing U.S. utilities, international 

power generators, equipment suppliers, government research organizations, coal and 

oil companies, and a railroad—see crucial roles for both industry and governments 

worldwide in aggressively pursuing collaborative RD&D over the next 20+ years to 

create a full portfolio of commercially self-sustaining, competitive advanced coal 

power generation and CCS technologies. 

Key Points: 

• Advanced coal power plant technologies with integrated CO2 capture and storage (CCS) will be crucial to lowering U.S. electric power sector CO2 emissions. 

They will also be crucial to substantially lowering global CO2 emissions. 

• The availability of advanced coal power and integrated CCS and other technologies could dramatically reduce the projected increases in the cost of wholesale electricity under a carbon cap. 

• It is important to avoid choosing between coal technology options. We should 

foster a full portfolio of technologies. 

• While there are well-proven methods for capturing CO2 resulting from coal gasification, no IGCC plant captures CO2. IGCC technology is still relatively new 

and in need of more commercial installations. 

• PC technology is already well proven commercially in the power industry, although potential for significant improvement exists; the need is for demonstration of post combustion capture at a commercial and affordable scale. 

• There will inevitably be additional costs associated with CCS. EPRI’s latest estimates suggest that the levelized cost of electricity (COE) from new coal plants 

(IGCC or supercritical PC) designed for capture, compression, transportation 

and storage of the CO2 will be 40–80 percent higher than the COE of a conventional supercritical PC (SCPC) plant. 

• EPRI’s technical assessment work indicates that the preferred technology and 

the additional cost of electricity for CCS will depend on the coal type, location 

and the technology employed. Without CCS, SCPC has an advantage over 

IGCC. However, the additional CCS cost is generally lower with IGCC than for 

SCPC. 

• Some studies show an advantage for IGCC with CCS with bituminous coal. 

With lignite coal, SCPC with CCS is generally preferred. With sub-bituminous 

coal, SCPC with CCS and IGCC with CCS appear to show similar costs. 

• Our initial work with post-combustion CO2 capture technologies suggests we 

can potentially reduce the current estimated 30 percent energy penalty associated with CCS to about 15 percent over the longer-term. Improvements in IGCC 

plants offer a comparable potential for reducing the cost and energy penalty as 

well. 

• The key to proving CCS capability is the demonstration of CCS at large-scale 

(i.e., on the order of 1 million tons CO2/year) for both pre- and post-combustion 

capture and oxy-combustion with storage in a variety of geologies. Large combined capture and storage demonstrations should be encouraged in different regions and with different coals and technologies. 

• EPRI’s CoalFleet for Tomorrow program has identified the RD&D pathways to 

demonstrate, by 2025, a full portfolio of economically attractive, commercialscale advanced coal power and integrated CCS technologies suitable for use 

with the broad range of U.S. coal types. EPRI is currently developing collaborations to develop and demonstrate a series of IGCC and post combustion capture 

processes to improve the cost and energy use of integrated gasification plus capture and post combustion technologies. Some technologies will be ready for some 

49 

fuels sooner, but the economic benefits of competition are not achieved until the 

full portfolio is developed. 

• The identified RD&D is estimated to cost $8 billion between now and 2017 and 

$17 billion cumulatively by 2025, and we need to begin immediately to ensure 

that these climate change solution technologies will be fully tested at scale by 

2025. 

• Major non-technical barriers associated with CO2 storage need to be addressed 

before CCS can become a commercial reality, including resolution of regulatory 

and long-term liability uncertainties. 

The Role of Advanced Coal Generation With CO2 Capture and Storage in 

a Carbon-Constrained Future 

Coal currently provides over half of the electricity used in the United States, and 

most forecasts of future energy use in the United States show that coal will continue 

to have a dominant share in our electric power generation for the foreseeable future. 

Coal is a stably priced, affordable, domestic fuel that can be used in an environmentally responsible manner. Through development of advanced pollution control 

technologies and sensible regulatory programs, emissions of criteria air pollutants 

from new coal-fired power plants have been reduced by more than 90 percent over 

the past three decades. And by displacing otherwise needed imports of natural gas 

or fuel oil, coal helps address America’s energy security and reduces our trade deficit with respect to energy. 

EPRI’s ‘‘Electricity Technology in a Carbon-Constrained Future’’ study suggests 

that it is technically feasible to reduce U.S. electric sector CO2 emissions by 25–30 

percent relative to current emissions by 2030 while meeting the increased demand 

for electricity. The study showed that the largest single contributor to emissions reduction would come from the integration of CCS technologies with advanced coalbased power plants coming on-line after 2020. 

Economic analyses of scenarios to achieve the study’s emission reduction goals 

show that in 2050, a U.S. electricity generation mix based on a full portfolio of technologies, including advanced coal technologies with integrated CCS and advanced 

light water nuclear reactors, results in wholesale electricity prices at less than half 

of the wholesale electricity price for a generation mix without advanced coal/CCS 

and nuclear power. In the case with advanced coal/CCS and nuclear power, the cost 

to the U.S. economy of a CO2 emissions reduction policy is $1 trillion less than in 

the case without advanced coal/CCS and nuclear power, with a much stronger manufacturing sector. Both of these analyses are documented in the 2007 EPRI Summer 

Seminar Discussion paper, ‘‘The Power to Reduce CO2 Emissions—the Full Portfolio,’’ available at http://epri-reports.org/DiscussionPaper2007.pdf. 

Accelerating RD&D on Advanced Coal Technologies With CO2 Capture and 

Storage—Investment and Time Requirements 

The portfolio aspect of advanced coal with integrated CCS technologies must be 

emphasized because no single advanced coal technology (or any generating technology) has clear-cut economic advantages across the range of U.S. applications. The 

best strategy for meeting future electricity needs while addressing climate change 

concerns and minimizing economic disruption lies in developing a full portfolio of 

technologies from which power producers (and their regulators) can choose the option best suited to local conditions and preferences and provide power at the lowest 

cost to the customer. Toward this end, four major technology efforts related to CO2

emissions reduction from coal-based power systems must be undertaken: 

1. Increased efficiency and reliability of IGCC power plants 

2. Increased thermodynamic efficiency of PC power plants 

3. Improved technologies for capture of CO2 from coal combustion- and gasification-based power plants 

4. Reliable, acceptable technologies for long-term storage of captured CO2

Identification of mechanisms to share RD&D financial and technical risks and to 

address legal and regulatory uncertainties must take place as well. 

In short, a comprehensive recognition of all the factors needed to hasten deployment of competitive, commercial advanced coal and integrated CO2 capture and 

storage technologies—and implementation of realistic, pragmatic plans to overcome 

barriers—is the key to meeting the challenge to supply affordable, environmentally 

responsible energy in a carbon-constrained world. 

A typical path to develop a technology to commercial maturity consists of moving 

from the conceptual stage to laboratory testing, to small pilot-scale tests, to largerscale tests, to multiple full-scale demonstrations, and finally to deployment in fullVerDate Nov 24 2008 13:10 May 24, 2012 Jkt 074322 PO 00000 Frm 00053 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\74322.TXT SCOM1 PsN: JACKIE
50 

2 IEA Greenhouse Gas R&D Programme (IEA GHG), ‘‘Estimating Future Trends in the Cost 

of CO2 Capture Technologies,’’ 2006/5, January 2006. 

scale commercial operations. For capital-intensive technologies such as advanced 

coal power systems, each stage can take years or even a decade to complete, and 

each sequential stage entails increasing levels of investment. As depicted in Figure 

1, several key advanced coal power and CCS technologies are now in (or approaching) an ‘‘adolescent’’ stage of development. This is a time of particular vulnerability 

in the technology development cycle, as it is common for the expected costs of fullscale application to be higher than earlier estimates when less was known about 

scale-up and application challenges. Public agency and private funders can become 

disillusioned with a technology development effort at this point, but as long as fundamental technology performance results continue to meet expectations, and a path 

to cost reduction is clear, perseverance by project sponsors in maintaining momentum is crucial. 

Unexpectedly high costs at the mid-stage of technology development have historically come down following market introduction, experience gained from ‘‘learningby-doing,’’ realization of economies of scale in design and production as order volumes rise, and removal of contingencies covering uncertainties and first-of-a-kind 

costs. An International Energy Agency study led by Carnegie Mellon University 

(CMU) observed this pattern of cost-reduction-over-time for power plant environmental controls, and CMU predicts a similar reduction in the cost of power plant 

CO2 capture technologies as the cumulative installed capacity grows.2 EPRI concurs 

with their expectations of experience-based cost reductions and believes that RD&D 

on specifically identified technology refinements can lead to greater cost reductions 

sooner in the deployment phase. 

Of the coal-based power generating and carbon sequestration technologies shown 

in Figure 1, only SCPC technology has reached commercial maturity. It is crucial 

that other technologies in the portfolio—namely ultra-supercritical (USC) PC, IGCC, 

CO2 capture (pre-combustion, post-combustion, and oxy-combustion), and CO2 storage—be given sufficient support to reach the stage of declining constant dollar costs 

before society’s requirements for greenhouse gas reductions compel their application 

in large numbers. 

Figure 2 depicts the major activities in each of the four technology areas that 

must take place to achieve a robust set of integral advanced coal/CCS solutions. 

Please note that UltraGen III is not included in Figure 2 but the schedule for ‘‘Design, construction & operation of NZE USC PC at up to 1,400 °F w/capture’’ is expected to commence around 2020. Important, but not shown in the figure, are the 

interactions between RD&D activities. For example, the ion transport membrane 

(ITM) oxygen supply technology shown under IGCC may also be able to be applied 

to oxy-combustion PC units. Further, while the individual goals related to efficiency, 

CO2 capture, and CO2 storage present major challenges, significant challenges also 


409novak1b.eps
51 

arise from complex interactions that occur when CO2 capture processes are integrated with gasification- and combustion-based power plant processes. 

Reducing CO2 Emissions Through Improved Coal Power Plant Efficiency— 

A Key Companion to CCS That Lowers Cost and Energy Requirements 

Improved thermodynamic efficiency reduces CO2 emissions by reducing the 

amount of fuel required to generate a given amount of electricity. A two-percentage 

point gain in efficiency provides a reduction in fuel consumption of roughly 5 percent and a similar reduction in flue gas and CO2 output. Because the size and cost 

of CO2 capture equipment is determined by the volume of flue gas to be treated, 

higher power block efficiency reduces the capital and energy requirements for CCS. 

Depending on the technology used, improved efficiency can also provide similar reductions in criteria air pollutants, hazardous air pollutants, and water consumption. 

A typical baseloaded 500 MW (net) coal plant emits about 3 million metric tons 

of CO2 per year. Individual plant emissions vary considerably given differences in 

plant steam cycle, coal type, capacity factor, and operating regimes. For a given fuel, 

however, a new supercritical PC unit built today might produce 5–10 percent less 

CO2 per megawatt-hour (MWh) than the existing fleet average for that coal type. 

With an aggressive RD&D program on efficiency improvement, new USC PC 

plants could reduce CO2 emissions per MWh by up to 25 percent relative to the existing fleet average. Significant efficiency gains are also possible for IGCC plants by 

employing advanced gas turbines and through more energy-efficient oxygen plants 

and synthesis (fuel) gas cleanup technologies. 

EPRI and the Coal Utilization Research Council (CURC), in consultation with 

DOE, have identified a challenging but achievable set of milestones for improvements in the efficiency, cost, and emissions of PC and coal-based IGCC plants. The 

EPRI–CURC Roadmap projects an overall improvement in the thermal efficiency of 

state-of-the art generating technology from 38–41 percent in 2010 to 44–49 percent 

by 2025 (on a higher heating value [HHV] basis; see Table 1). As Table 1 indicates, 

power-block efficiency gains (i.e., without capture systems) will be offset by the energy required for CO2 capture, but as noted, they are important in reducing the 

overall cost of CCS. Coupled with opportunities for major improvements in the energy efficiency of CO2 capture processes per se, aggressive pursuit of the EPRI– 

CURC RD&D program offers the prospect of coal power plants with CO2 capture in 

2025 that have net efficiencies meeting or exceeding current-day power plants without CO2 capture. 


409novak2.eps
52 

It is also important to note that the numeric ranges in Table 1 are not simply 

a reflection of uncertainty, but rather they underscore an important point about differences among U.S. coals. The natural variations in moisture and ash content and 

combustion characteristics between coals have a significant impact on attainable efficiency. An advanced coal plant firing Wyoming and Montana’s Powder River Basin 

(PRB) coal, for example, would likely have an HHV efficiency 2 percentage points 

lower than the efficiency of a comparable plant firing Appalachian bituminous coals. 

Equally advanced plants firing lignite would ikely have efficiencies 2 percentage 

points lower than their counterparts firing PRB. Any government incentive program 

with an efficiency-based qualification criterion should recognize these inherent differences in the attainable efficiencies for plants using different ranks of coal. 

Table 1.—Efficiency Milestones in EPRI-CURC Roadmap 

2010 2015 2020 2025 

PC & IGCC Systems 

(Without CO2 Capture) 38–41% HHV 39–43% HHV 42–46% HHV 44–49% HHV 

PC & IGCC Systems 

(With CO2 Capture *) 31–32% HHV 31–35% HHV 33–39% HHV 39–46% HHV 

* Efficiency values reflect impact of 90 percent CO2 capture, but not compression or transportation. 

New Plant Efficiency Improvements—IGCC 

Although IGCC is not yet a mature technology for coal-fired power plants, chemical plants around the world have accumulated a 100-year experience base operating 

coal-based gasification units and related gas cleanup processes. The most advanced 

of these units are similar to the front end of a modern IGCC facility. Similarly, several decades of experience firing natural gas and petroleum distillate have established a high level of maturity for the basic combined cycle generating technology. 

Nonetheless, ongoing RD&D continues to provide significant advances in the base 

technologies, as well as in the suite of technologies used to integrate them into an 

IGCC generating facility. 

Efficiency gains in currently proposed IGCC plants will come from the use of new 

‘‘FB-class’’ gas turbines, which will provide an overall plant efficiency gain of about 

0.6 percentage point (relative to IGCC units with FA-class models, such as Tampa 

Electric’s Polk Power Station). This corresponds to a decrease in the rate of CO2

emissions per MWh of about 1.5 percent. Alternatively, this means 1.5 percent less 

fuel is required per MWh of output, and thus the required size of pre-combustion 

water-gas shift and CO2 separation equipment would be slightly smaller. 

Figure 3 depicts the anticipated time-frame for further developments identified by 

EPRI’s CoalFleet for Tomorrow program that promise a succession of significant 

improvements in IGCC unit efficiency. Key technology advances under development 

include: 

• larger capacity gasifiers (often via higher operating pressures that boost 

throughput without a commensurate increase in vessel size) 

• integration of new gasifiers with larger, more efficient G- and H-class gas turbines 

• use of ion transport membrane or other more energy-efficient technologies in oxygen plants 

• warm synthesis gas cleanup and membrane separation processes for CO2 capture that reduce energy losses in these areas 

• recycle of liquefied CO2 to replace water in gasifier feed slurry (reducing heat 

loss to water evaporation) 

• hybrid combined cycles using fuel cells to achieve generating efficiencies exceeding those of conventional combined cycle technology 

Improvements in gasifier reliability and in control systems also contribute to improved annual average efficiency by minimizing the number and duration of 

startups and shutdowns. 

53 

Counteracting Gas Turbine Output Loss at High Elevations. IGCC plants designed 

for application in high-elevation locations must account for the natural reduction in 

gas turbine power output that occurs where the air is thin. This phenomenon is 

rooted in the fundamental volumetric flow limitation of a gas turbine, and can reduce power output by up to 15 percent at an elevation of 5,000 feet (relative to a 

comparable plant at sea level). EPRI is exploring measures to counteract this power 

loss, including inlet air chilling (a technique used at natural gas power plants to 

mitigate the power loss that comes from thinning of the air on a hot day) and use 

of supplemental burners between the gas turbine and steam turbine to boost the 

plant’s steam turbine section generating capacity. 

Larger, Higher Firing Temperature Gas Turbines. For plants coming on-line 

around 2015, the larger size G-class gas turbines, which operate at higher firing 

temperatures (relative to F-class machines) can improve efficiency by 1 to 2 percentage points while also decreasing capital cost per kW capacity. The H-class gas turbines coming on-line in the same timeframe, which also feature higher firing temperatures as well as steam-based internal cooling of hot turbine components, will 

provide a further increase in efficiency and capacity. 

Ion Transport Membrane-Based Oxygen Plants. Most gasifiers used in IGCC 

plants require a large quantity of high-pressure, high purity oxygen, which is typically generated onsite with an expensive and energy-intensive cryogenic process. 

The ITM process allows the oxygen in high-temperature air to pass through a membrane while preventing passage of non-oxygen atoms. According to developers, an 

ITM-based oxygen plant consumes 35–60 percent less power and costs 35 percent 

less than a cryogenic plant. DOE has been supporting development of this technology. EPRI is performing a due diligence assessment of this technology in advance 

of potential participation in technology scale-up efforts and is planning to solicit an 

industry consortium to support development. 

Supercritical Heat Recovery Steam Generators. In IGCC plants, hot exhaust gas 

exiting the gas turbine is ducted into a heat exchanger known as a heat recovery 

steam generator (HRSG) to transfer energy into water-filled tubes producing steam 

to drive a steam turbine. This combination of a gas turbine and steam turbine 

power cycles produces electricity more efficiently than either a gas turbine or steam 


409novak3.eps
54 

turbine alone. As with conventional steam power plants, the efficiency of the steam 

cycle in a combined cycle plant increases when turbine inlet steam temperature and 

pressure are increased. The higher exhaust temperatures of G- and H-class gas turbines offer the potential for adoption of more-efficient supercritical steam cycles. 

Materials for use in a supercritical HRSG are generally established, and thus 

should not pose a barrier to technology implementation once G- and H-class gas turbines become the standard for IGCC designs. 

Synthesis Gas Cleaning at Higher Temperatures. The acid gas recovery (AGR) 

processes currently used to remove sulfur compounds from synthesis gas require 

that the gas and solvent be cooled to about 100 °F, thereby causing a loss in efficiency. Further costs and efficiency loss are inherent in the process equipment and 

auxiliary steam required to recover the sulfur compounds from the solvent and convert them to useable products. Several DOE-sponsored RD&D efforts aim to reduce 

the energy losses and costs imposed by this recovery process. These technologies (described below) could be ready—with adequate RD&D support—by 2020: 

• The Selective Catalytic Oxidation of Hydrogen Sulfide process eliminates the 

Claus and Tail Gas Treating units, along with the traditional solvent-based 

AGR contactor, regenerator, and heat exchangers, by directly converting hydrogen sulfide (H2S) to elemental sulfur. The process allows for a higher operating 

temperature of approximately 300 °F, which eliminates part of the low-temperature gas cooling train. The anticipated benefit is a net capital cost reduction of 

about $60/kW along with an efficiency gain of about 0.8 percentage point. 

• The RTI/Eastman High-Temperature Desulfurization System uses a regenerable 

dry zinc oxide sorbent in a dual loop transport reactor system to convert H2S 

and COS to H2O, CO2, and SO2. Tests at Eastman Chemical Company have 

shown sulfur species removal rates above 99.9 percent, with 10 ppm output 

versus 8,000+ ppm input sulfur, using operating temperatures of 800–1,000 °F. 

This process is also being tested for its ability to provide a high-pressure CO2

by-product. The anticipated benefit for IGCC, compared with using a standard 

oil-industry process for sulfur removal, is a net capital cost reduction of $60– 

$90 per kW, a thermal efficiency gain of 2–4 percent for the gasification process, 

and a slight reduction in operating cost. Tests are also under way for a multicontaminant removal processes that can be integrated with the transport 

desulfurization system at temperatures above 480 °F. 

Liquid CO2-Coal Slurrying for Gasification of Low-Rank Coals. Future IGCC 

plants with CCS may recycle some of the recovered liquid CO2 to replace water as 

the slurrying medium for the coal feed. This is expected to increase gasification efficiency for all coals, but particularly for subbituminous coal and lignite, which have 

naturally high moisture contents. The liquid CO2 has a lower heat of vaporization 

than water and is able to carry more coal per unit mass of fluid. The liquid CO2- coal slurry will flash almost immediately upon entering the gasifier, providing good 

dispersion of the coal particles and potentially yielding the higher performance of 

a dry-fed gasifier with the simplicity of a slurry-fed system. 

Traditionally, slurry-fed gasification technologies have a cost advantage over conventional dry-fed fuel handling systems, but they suffer a large performance penalty 

when used with coals containing a large fraction of water and ash. EPRI identified 

CO2 coal slurrying as an innovative fuel preparation concept 20 years ago, when 

IGCC technology was in its infancy. At that time, however, the cost of producing 

liquid CO2 was too high to justify the improved thermodynamic performance. Requirements for CCS change that, as it will substantially reduce the incremental cost 

of producing a liquid CO2 stream. 

To date, CO2-coal slurrying has only been demonstrated at pilot scale and has yet 

to be assessed in feeding coal to a gasifier, so the estimated performance benefits 

remain to be confirmed. It will first be necessary, however, to update previous studies to quantify the potential benefit of liquid CO2 slurries with IGCC plants designed for CO2 capture. If the predicted benefit is economically advantageous, a significant amount of scale-up and demonstration work would be required to qualify 

this technology for commercial use. 

Fuel Cells and IGCC. No matter how far gasification and turbine technologies advance, IGCC power plant efficiency will never progress beyond the inherent thermodynamic limits of the gas turbine and steam turbine power cycles (along with lower 

limits imposed by available materials technology). Several IGCC-fuel cell hybrid 

power plant concepts (IGFC) aim to provide a path to coal-based power generation 

with net efficiencies that exceed those of conventional combined cycle generation. 

Along with its high thermal efficiency, the fuel cell hybrid cycle reduces the energy consumption for CO2 capture. The anode section of the fuel cell produces a 

stream that is highly concentrated in CO2. After removal of water, this stream can 

55 

be compressed for sequestration. The concentrated CO2 stream is produced without 

having to include a water-gas shift reactor in the process (see Figure 4). This further improves the thermal efficiency and decreases capital cost. IGFC power systems are a long-term solution, however, and are unlikely to see full-scale demonstration until about 2030. 

The Changing Role of FutureGen. In January of this year, DOE announced a restructured approach to the FutureGen project. Previously, the FutureGen Industrial 

Alliance and DOE were intending to build a first-of-its-kind, near-zero emissions 

coal-fed IGCC power plant integrated with CCS. The commencement of full-scale operations was targeted for 2013. The project aimed at storing CO2 in a representative 

geologic formation at a rate of at least one million metric tons per year. DOE had 

committed to spend $1.1 billion in support of the project while the FutureGen Industrial Alliance had agreed to contribute $400 million. 

Under its revised approach, DOE will offer to pay the additional cost of capturing 

CO2 at multiple IGCC plants. Each plant would capture and store at least 1 million 

tons of CO2 per year. DOE’s goal is to have the plants in operation between 2015 

and 2016. 

The original FutureGen concept was meant to serve as a ‘‘living laboratory’’ for 

testing advanced technologies that offered the promise of clean environmental performance at a reduced cost and increased reliability. The original FutureGen concept, as shown in Figure 5 was to have the flexibility to conduct full-scale and slipstream tests of such scalable advanced technologies as: 

• Membrane processes to replace cryogenic separation for oxygen production 

• An advanced transport reactor sidestream with 30 percent of the capacity of the 

main gasifier 

• Advanced membrane and solvent processes for H2 and CO2 separation 

• A raw gas shift reactor that reduces the upstream clean-up requirements 

• Ultra-low-NOX combustors that can be used with high-hydrogen synthesis gas 

• A fuel cell hybrid combined cycle pilot 

• Smart dynamic plant controls including a CO2 management system 


409novak4a.eps
56 

While the revised DOE FutureGen concept will meet the original goal of having 

a CCS test of at least 1 million tons of CO2 per year (albeit two to 3 years later 

than the original target), the other original goal of also hosting the development of 

several advanced technologies for decreasing plant costs appears to have been 

dropped. 

EPRI has responded to DOE’s RFI on the revised FutureGen concept. We asked 

for clarification on what aspects of the costs of including CO2 capture and storage 

(CCS) would be covered, and we gave our estimate of what the total costs would 

be for including CCS on one train of a two-train 600 MW IGCC. We also highlighted 

the other major RD&D activities that are needed for improving the efficiency and 

cost of IGCC technologies with CO2 capture (see Figure 6). In addition, we asked 

whether non-IGCC coal power plants which capture at least 1 million tons of CO2

per year could qualify for funding under the revised FutureGen concept. For example, would the incremental CCS costs of a project such as our proposed UltraGen 

advanced SCPC plant with post-combustion capture and geological storage of CO2

be eligible for DOE support under the restructured FutureGen concept. 

New Plant Efficiency Improvements—Advanced Pulverized Coal 

Pulverized-coal power plants have long been a primary source of reliable and affordable power in the United States and around the world. The advanced level of 


409novak5.eps 409novak6.eps
57 

maturity of the technology, along with basic thermodynamic principles, suggests 

that significant efficiency gains can most readily be realized by increasing the operating temperatures and pressures of the steam cycle. Such increases, in turn, can 

be achieved only if there is adequate development of suitable materials and new 

boiler and steam turbine designs that allow use of higher steam temperatures and 

pressures. 

Current state-of-the-art plants use supercritical main steam conditions (i.e., temperature and pressure above the ‘‘critical point’’ where the liquid and vapor phases 

of water are indistinguishable). SCPC plants typically have main steam conditions 

up to 1,100 °F. The term ‘‘ultra-supercritical’’ is used to describe plants with main 

steam temperatures in excess of 1,100 °F and potentially as high as 1,400 °F. 

Achieving higher steam temperatures and higher efficiency will require the development of new corrosion-resistant, high-temperature nickel alloys for use in the boiler and steam turbine. In the United States, these challenges are being address by 

the Ultra-Supercritical Materials Consortium, a DOE R&D program involving Energy Industries of Ohio, EPRI, the Ohio Coal Development Office, and numerous 

equipment suppliers. EPRI provides technical management for the Consortium. Results are applicable to all ranks of coal. As noted, higher power block efficiencies 

translate to lower costs for post-combustion CO2 capture equipment. 

It is expected that a USC PC plant operating at about 1,300 °F will be built during the next seven to 10 years, following the demonstration and commercial availability of advanced materials from these programs. This plant would achieve an efficiency (before installation of CO2 capture equipment) of about 45 percent (HHV) on 

bituminous coal, compared with 39 percent for a current state-of-the-art plant, and 

would reduce CO2 production per net MWh by about 15 percent. 

Ultimately, nickel-base alloys are expected to enable stream temperatures in the 

neighborhood of 1,400 °F and pre-capture generating efficiencies up to 47 percent 

HHV with bituminous coal. This approximately 10 percentage point improvement 

over the efficiency of a new subcritical pulverized-coal plant would equate to a decrease of about 25 percent in CO2 and other emissions per MWh. The resulting saving in the cost of subsequently installed CO2 capture equipment is substantial. 

Figure 7 illustrates a timeline developed by EPRI’s CoalFleet for Tomorrow program to establish efficiency improvement and cost reduction goals for USC PC 

plants with CO2 capture. 


409novak7.eps
58 

UltraGen Ultrasupercritical (USC) Pulverized Coal (PC) Commercial Projects. 

EPRI and industry representatives have proposed a program to support commercial 

projects that demonstrate advanced PC and CCS technologies. The vision entails 

construction of two (or more) commercially operated USC PC power plants that combine state-of-the-art pollution controls, ultra-supercritical steam power cycles, and 

innovative CO2 capture technologies. 

The UltraGen I plant will use the best of today’s proven ferritic steels in hightemperature boiler and steam turbine components, while UltraGen II will be the 

first plant in the United States to feature nickel-based alloys and is designed for 

steam temperatures up to 1,300 °F. UltraGen III will be designed for steam temperatures up to 1,400 °F using materials currently under development by the DOE 

boiler and steam turbine materials program. 

UltraGen I will demonstrate CO2 capture modules that separate about 1 million 

tons CO2/yr using the best-established technology. This system will be about 6 times 

the size of the largest CO2 capture system operating on a coal-fired boiler today, and 

will be integrated into the thermal cycle of the boiler to minimize parasitic loads 

and capacity loss. UltraGen II will at least double the size of the UltraGen I CO2

capture system, and may demonstrate a new class of chemical solvent if one of the 

emerging low-regeneration-energy processes has reached a sufficient stage of development. UltraGen III is expected to capture up to 90 percent of the CO2, 3.5 times 

more than for UltraGen I. All three plants will demonstrate ultra-low emissions, 

and dry and compress the captured CO2 to demonstrate long-term geologic storage 

and/or use in enhanced oil or gas recovery operations. Figure 8 depicts the proposed 

key features of UltraGen I, II, and III. 


409novak8.eps
59 

To provide a platform for testing and developing emerging PC and CCS technologies, the UltraGen program will allow for technology trials at existing sites as 

well as at the sites of new projects. Unlike FutureGen, EPRI expects the UltraGen 

projects will be commercially dispatched by electricity grid operators. If the 

FutureGen concept could accommodate post combustion capture the differential cost 

of UltraGen CCS could be part of the full portfolio of projects. The differential cost 

to the host company for demonstrating these improved features are envisioned to 

be offset by any available tax credits (or other incentives) and by funds raised 

through an industry-led consortium formed by EPRI. 

The UltraGen projects represent the type of ‘‘giant step’’ collaborative efforts that 

need to be taken to advance integrated PC/CCS technology to the next phase of evolution and assure competitiveness in a carbon-constrained world. Because of the 

time and expense for each ‘‘design and build’’ iteration for coal power plants (3 to 

5 years not counting the permitting process and ∼$2 billion), there is no room for 

hesitation in terms of commitment to advanced technology validation and demonstration projects. EPRI is currently discussing the UltraGen project concept with 


409novak9.eps 409novak10.eps
60 

several firms in the U.S. and internationally, and plans to develop a consortium to 

support demonstration of the technology. 

The UltraGen projects will resolve technical and economic barriers to the deployment of USC PC and CCS technology by providing a shared-risk vehicle for testing 

and validating high-temperature materials, components, and designs in plants also 

providing superior environmental performance. 

Figure 9 summarizes EPRI’s recommended major RD&D activities for improving 

the efficiency and cost of USC PC technologies with CO2 capture. Please note that 

UltraGen III is not included in Figure 9 but the schedule for ‘‘Design, construction 

& operation of NZE USC PC at up to 1,400 °F w/capture’’ is expected to commence 

around 2020. 

Efficiency Improvement and CCS Retrofits for the Existing PC Fleet. It would be 

economically advantageous to operate the many reliable subcritical PC units in the 

U.S. fleet well into the future. Premature replacement of these units or mandatory 

retrofit of these units for CO2 capture en masse would be economically prohibitive. 

Their flexibility for load following and provision of support services to ensure grid 

stability makes them highly valuable. With equipment upgrades, many of these 

units can realize modest efficiency gains, which, when accumulated across the existing generating fleet could make a sizable reduction in CO2 emissions. For some existing plants, retrofit of CCS will make sense, but specific plant design features, 

space limitations, and economic and regulatory considerations must be carefully 

analyzed to determine whether retrofit-for-capture is feasible. 

These upgrades depend on the equipment configuration and operating parameters 

of a particular plant and may include: 

• turbine blading and steam path upgrades 

• turbine control valve upgrades for more efficient regulation of steam 

• cooling tower and condenser upgrades to reduce circulating water temperature, 

steam turbine exhaust backpressure, and auxiliary power consumption 

• cooling tower heat transfer media upgrades 

• condenser optimization to maximize heat transfer and minimize condenser temperature 

• condenser air leakage prevention/detection 

• variable speed drive technology for pump and fan motors to reduce power consumption 

• air heater upgrades to increase heat recovery and reduce leakage 

• advanced control systems incorporating neural nets to optimize temperature, 

pressure, and flow rates of fuel, air, flue gas, steam, and water 

• optimization of water blowdown and blowdown energy recovery 

• optimization of attemperator design, control, and operating scenarios 

• sootblower optimization via ‘‘intelligent’’ sootblower system use 

• coal drying (for plants using lignite and subbituminous coals) 

Coal Drying for Increased Generating Efficiency. Boilers designed for high-moisture lignite have traditionally employed higher feed rates (lb/hr) to account for the 


409novak11.eps
61 

3 C. Bullinger, M. Ness, and N. Sarunac, ‘‘One Year of Operating Experience with Prototype 

Fluidized Bed Coal Dryer at Coal Creek Generating Station,’’ 32nd International Technical Conference on Coal Utilization and Fuel Systems, Clearwater, FL, June 10–15, 2007. 

large latent heat load to evaporate fuel moisture. An innovative concept developed 

by Great River Energy (GRE) and Lehigh University uses low-grade heat recovered 

from within the plant to dry incoming fuel to the boiler, thereby boosting plant efficiency and output. [In contrast, traditional thermal drying processes are complex 

and require high-grade heat to remove moisture from the coal.] Specifically, the 

GRE approach uses steam condenser and boiler exhaust heat exchangers to heat air 

and water fed to a fluidized-bed coal dryer upstream of the plant pulverizers. Based 

on successful tests with a pilot-scale dryer and more than a year of continuous operation with a prototype dryer at its Coal Creek station, GRE (with U.S. Department 

of Energy support and EPRI technical consultation) is now building a full suite of 

dryers for Unit 2 (i.e., a commercial-scale demonstration). In addition to the efficiency and CO2 emission reduction benefits from reducing the lignite feed moisture 

content by about 25 percent, the plant’s air emissions will be reduced as well.3 Application of this technology is not limited to PC units firing lignite. EPRI believes 

it may find application in PC units firing subbituminous coal and in IGCC units 

with dry-fed gasifiers using low-rank coals. 

Improving CO2 Capture Technologies 

CCS entails pre-combustion or post-combustion CO2 capture technologies, CO2

drying and compression (and sometimes further removal of impurities), and the 

transportation of separated CO2 to locations where it can be stored away from the 

atmosphere for centuries or longer. 

Albeit at considerable cost, CO2 capture technologies can be integrated into all 

coal-based power plant technologies. For both new plants and retrofits, there is a 

tremendous need (and opportunity) to reduce the energy required to remove CO2

from fuel gas or flue gas. Figure 10 shows a selection of the key technology developments and test programs needed to achieve commercial CO2 capture technologies for 

advanced coal combustion- and gasification-based power plants at a progressively 

shrinking constant-dollar levelized cost-of-electricity premium. Specifically, the target is a premium of about $6/MWh in 2025 (relative to plants at that time without 

capture) compared with an estimated 2010 cost premium of perhaps $40/MWh (not 

counting the cost of transportation and storage). Such a goal poses substantial engineering challenges and will require major investments in RD&D to roughly halve 

the currently large energy requirements (operating costs) associated with CO2 solvent regeneration. Achieving this goal will allow power producers to meet the public 

demand for stable electricity prices while reducing CO2 emissions to address climate 

change concerns. 

Pre-Combustion CO2 Capture (IGCC) 

IGCC technology allows for CO2 capture to take place via an added fuel gas processing step at elevated pressure, rather than at the atmospheric pressure of postcombustion flue gas, permitting capital savings through smaller equipment sizes as 

well as lower operating costs. 

Currently available technologies for such pre-combustion CO2 removal use a 

chemical and/or physical solvent that selectively absorbs CO2 and other ‘‘acid gases,’’ 

such as hydrogen sulfide. Application of this technology requires that the CO in synthesis gas (the principal component) first be ‘‘shifted’’ to CO2 and hydrogen via a 

catalytic reaction with water. The CO2 in the shifted synthesis gas is then removed 


409novak12.eps
62 

via contact with the solvent in an absorber column, leaving a hydrogen-rich synthesis gas for combustion in the gas turbine. The CO2 is released from the solvent 

in a regeneration process that typically reduces pressure and/or increases temperature. 

Chemical plants currently employ such a process commercially using methyl 

diethanolamine (MDEA) as a chemical solvent or the Selexol and Rectisol processes, 

which rely on physical solvents. Physical solvents are generally preferred when extremely high (>99.8 percent) sulfur species removal is required. Although the required scale-up for IGCC power plant applications is less than that needed for scaleup of post-combustion CO2 capture processes for PC plants, considerable engineering 

challenges remain and work on optimal integration with IGCC cycle processes has 

just begun. 

The impact of current pre-combustion CO2 removal processes on IGCC plant thermal efficiency and capital cost is significant. In particular, the water-gas shift reaction reduces the heating value of synthesis gas fed to the gas turbine. Because the 

gasifier outlet ratios of CO to methane to H2 are different for each gasifier technology, the relative impact of the water-gas shift reactor process also varies. In general, however, it can be on the order of a 10 percent fuel energy reduction. Heat 

regeneration of solvents further reduces the steam available for power generation. 

Other solvents, which are depressurized to release captured CO2, must be re-pressurized for reuse. Cooling water consumption is increased for solvents needing cooling after regeneration and for pre-cooling and interstage cooling during compression 

of separated CO2 to a supercritical state for transportation and storage. Heat integration with other IGCC cycle processes to minimize these energy impacts is complex and is currently the subject of considerable RD&D by EPRI and others. 

Membrane CO2 Separation. Technology for separating CO2 from shifted synthesis 

gas (or flue gas from PC plants) offers the promise of lower auxiliary power consumption but is currently only at the laboratory stage of development. Several organizations are pursuing different approaches to membrane-based applications. In 

general, however, CO2 recovery on the low-pressure side of a selective membrane 

can take place at a higher pressure than is now possible with solvent processes, reducing the subsequent power demand for compressing CO2 to a supercritical state. 

Membrane-based processes can also eliminate steam and power consumption for regenerating and pumping solvent, respectively, but they require power to create the 

pressure difference between the source gas and CO2-rich sides. If membrane technology can be developed at scale to meet performance goals, it could enable up to 

a 50 percent reduction in capital cost and auxiliary power requirements relative to 

current CO2 capture and compression technology. 

Post-Combustion CO2 Capture (PC and Circulating Fluidized-Bed (CFB) Plants) 

The post-combustion CO2 capture processes being discussed for power plant boilers in the near-term draw upon commercial experience with amine solvent separation at much smaller scale in the food, beverage and chemical industries, including 

three U.S. applications of CO2 capture from coal-fired boilers. 

These processes contact flue gas with an amine solvent in an absorber column 

(much like a wet SO2 scrubber) where the CO2 chemically reacts with the solvent. 

The CO2-rich liquid mixture then passes to a stripper column where it is heated to 

change the chemical equilibrium point, releasing the CO2. The ‘‘regenerated’’ solvent 

is then recirculated back to the absorber column, while the released CO2 may be 

further processed before compression to a supercritical state for efficient transportation to a storage location. 

After drying, the CO2 released from the regenerator is relatively pure. However, 

successful CO2 removal requires very low levels of SO2 and NO2 entering the CO2

absorber, as these species also react with the solvent, requiring removal of the degraded solvent and replacement with fresh feed. Thus, high-efficiency SO2 and NOX

control systems are essential to minimizing solvent consumption costs for post-combustion CO2 capture; currently the approach to achieving such ultra-low SO2 concentrations is to add a polishing scrubber, a costly venture. Extensive RD&D is in 

progress to improve the solvent and system designs for power boiler applications 

and to develop better solvents with greater absorption capacity, less energy demand 

for regeneration, and greater ability to accommodate flue gas contaminants. 

At present, monoethanolamine (MEA) is the ‘‘default’’ solvent for post-combustion 

CO2 capture studies and small-scale field applications. Processes based on improved 

amines, such as Fluor’s Econamine FG Plus and Mitsubishi Heavy Industries’ KS– 

1, await demonstration at power boiler scale and on coal-derived flue gas. The potential for improving amine-based processes appears significant. For example, a recent study based on KS–1 suggests that its impact on net power output for a supercritical PC unit would be 19 percent and its impact on the levelized cost-of-elecVerDate Nov 24 2008 13:10 May 24, 2012 Jkt 074322 PO 00000 Frm 00066 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\74322.TXT SCOM1 PsN: JACKIE
63 

tricity would be 44 percent, whereas earlier studies based on suboptimal MEA applications yielded output penalties approaching 30 percent and cost-of-electricity penalties of up to 65 percent. 

Accordingly, amine-based engineered solvents are the subject of numerous ongoing 

efforts to improve performance in power boiler post-combustion capture applications. 

Along with modifications to the chemical properties of the sorbents, these efforts are 

addressing the physical structure of the absorber and regenerator equipment, examining membrane contactors and other modifications to improve gas-liquid contact 

and/or heat transfer, and optimizing thermal integration with steam turbine and 

balance-of-plant systems. Although the challenge is daunting, the payoff is potentially massive, as these solutions may be applicable not only to new plants, but to 

retrofits where sufficient plot space is available at the back end of the plant. 

Finally, as discussed earlier, deploying USC PC technology to increase efficiency 

and lower uncontrolled CO2 per MWh can further reduce the cost impact of postcombustion CO2 capture. 

Ammonia-Based Processes. Post-combustion CO2 capture using ammonia-based 

solvents offers the promise of significantly lower solvent regeneration requirements 

relative to MEA. In the ‘‘chilled ammonia’’ process owned by ALSTOM and currently 

under development and testing by ALSTOM and EPRI, respectively, CO2 is absorbed in a solution of ammonium carbonate, at low temperature and atmospheric 

pressure. 

Compared with amines, ammonium carbonate has over twice the CO2 absorption 

capacity and requires less than half the heat to regenerate. Further, regeneration 

can be performed under higher pressure than amines, so the released CO2 is already 

partially pressurized. Therefore, less energy is subsequently required for compression to a supercritical state for transportation to an injection location. Developers 

have estimated that the parasitic power loss from a full-scale supercritical PC plant 

using chilled ammonia CO2 capture could be as low as 15 percent, with an associated cost-of-electricity penalty of just 25 percent. Part of the reduction in power loss 

comes from the use of low quality heat to regenerate ammonia and reduce the quantity of steam required for regeneration. Following successful experiments at 0.25 

MWe scale, ALSTOM and a consortium of EPRI members built a 1.7 MWe pilot unit 

to test the chilled ammonia process on a flue gas slipstream at We Energies’ Pleasant Prairie Power Plant. Testing at this site began in late March 2008 and will continue for about 1 year. The American Electric Power Co. (AEP) has announced plans 

to test a scaled-up design (100,000 tons CO2/yr, equivalent to about 20 MWe), incorporating the lessons learned on the 1.7 MWe unit, at its Mountaineer station in 

West Virginia, with start-up scheduled for late 2009. AEP intends to capture, inject, 

and monitor for two-to-five years and, thereafter, continue monitoring CO2 location 

in the underground reservoir for another several years. EPRI plans to develop a consortium to support this Mountaineer CO2 Capture testing. 

Other ‘‘multi-pollutant’’ control system developers are also exploring ammoniabased processes for CO2 removal. For example, Powerspan and NRG Energy, Inc. 

announced plans in November 2007 to demonstrate a 125 MWe design of 

Powerspan’s ECO2 system at the Parish station in Texas starting up in 2012, and 

last month Basin Electric announced its selection of Powerspan to provide a similar 

size ECO2 system for its Antelope Valley station in North Dakota, also with a 2012 

start-up goal. 

Other Processes. EPRI has identified over 40 potential CO2 separation processes 

that are being developed by various firms or institutes. They include absorption systems (typically solvent-based similar to the amine and ammonia processes discussed 

above), adsorbed (attachment of the CO2 to a solid that is then regenerated and reused), membranes, and biological systems. Funding comes from a variety of sources, 

primarily DOE or internal funds, but the funding is neither sufficient or wellenough coordinated to advance the most promising technologies at the speed needed 

to achieve the goals of high CO2 capture at societally-acceptable cost and energy 

drain. EPRI is working with the Southern Co. to select and demonstrate one of 

these processes at the 20+ MWe scale, with the collected CO2 injected into a local 

underground saline reservoir. The capture portion of this project will be funded 

mostly by Southern Co., its process supplier, and a collaborative of electricity generation companies assembled by EPRI. The storage portion will be funded largely 

by DOE under Phase 3 of its Regional Carbon Sequestration Partnership, with cofunding from the private sector. Start-up of the capture unit and compression/transport/injection system is projected for late 2010. Southern Co. and its teammates intend to capture, inject, and monitor for about 4 years and, thereafter, continue monitoring CO2 location in the underground reservoir for another several years. 

64 

4http://www.co2captureandstorage.info/projectlspecific.php?projectlid=26. 

Oxy-Fuel Combustion Boilers 

Fuel combustion in a blend of oxygen and recycled flue gas rather than in air 

(known as oxy-fuel combustion, oxy-coal combustion, or oxy-combustion) is gaining 

interest as a viable CO2 capture alternative for PC and CFB plants. The process 

is applicable to virtually all fossil-fueled boiler types and is a candidate for retrofits 

as well as new power plants. 

Firing coal with high-purity oxygen alone would result in too high of a flame temperature, which would increase slagging, fouling, and corrosion problems, so the oxygen is diluted by mixing it with a slipstream of recycled flue gas. As a result, the 

flue gas downstream of the recycle slipstream take-off consists primarily of CO2 and 

water vapor (although it also contains small amounts of nitrogen, oxygen, and criteria pollutants). After the water is condensed, the CO2-rich gas is compressed and 

purified to remove contaminants and prepare the CO2 for transportation and storage. 

Oxy-combustion boilers have been studied in laboratory-scale and small pilot units 

of up to 3 MWt. Two larger pilot units, at ∼10 MWe, are now under construction 

by Babcock & Wilcox (B&W) and Vattenfall. An Australian-Japanese project team 

is pursuing a 30 MWe repowering project in Australia. These larger tests will allow 

verification of mathematical models and provide engineering data useful for designing pre-commercial systems. 

CO2 Transport and Geologic Storage 

Application of CO2 capture technologies implies that there will be secure and economical forms of long-term storage that can assure CO2 will be kept out of the atmosphere. Natural underground CO2 reservoirs in Colorado, Utah, and other western states testify to the effectiveness of long-term geologic CO2 storage. CO2 is also 

found in natural gas reservoirs, where it has resided for millions of years. Thus, evidence suggests that similarly sealed geologic formations will be ideal for storing CO2

for millennia or longer. 

The most developed approach for large-scale CO2 storage is injection into depleted 

or partially depleted oil and gas reservoirs and similar geologically sealed ‘‘saline 

formations’’ (porous rocks filled with brine that is impractical for desalination). Partially depleted oil reservoirs provide the potential added benefit of enhanced oil recovery (EOR). [EOR is used in mature fields to recover additional oil after standard 

extraction methods have been used. When CO2 is injected for EOR, it causes residual oil to swell and become less viscous, allowing some to flow to production wells, 

thus extending the field’s productive life.] By providing a commercial market for 

CO2 captured from industrial sources, EOR may help the economics of CCS projects 

where it is applicable, and in some cases might reduce regulatory and liability uncertainties. Although less developed than EOR, researchers are exploring the effectiveness of CO2 injection for enhancing production from depleted natural gas fields 

(particularly in compartmentalized formations where pressure has dropped) and 

from deep methane-bearing coal seams. DOE and the International Energy Agency 

are among the sponsors of such efforts. However, at the scale that CCS needs to 

be deployed to help achieve atmospheric CO2 stabilization at an acceptable level, 

EPRI believes that the primary economic driver for CCS will be the value of carbon 

that results from a future climate policy. 

Geologic sequestration as a CCS strategy is currently being demonstrated in several RD&D projects around the world. The three largest projects (which are nonpower)—Statoil’s Sleipner Saline Aquifer CO2 Storage project in the North Sea off 

of Norway; the Weyburn Project in Saskatchewan, Canada; and the In Salah Project 

in Algeria—each sequester about 1 million metric tons of CO2 per year, which 

matches the output of one baseloaded 150–200 MW coal-fired power plant. With 17 

collective operating years of experience, these projects have thus far demonstrated 

that CO2 storage in deep geologic formations can be carried out safely and reliably. 

Statoil estimates that Norwegian greenhouse gas emissions would have risen incrementally by 3 percent if the CO2 from the Sleipner project had been vented rather 

than sequestered.4

Table 2 lists a selection of current and planned CO2 storage projects as of early 

2007. Update to Table 2: The DF–1 Miller project has been put on hold and may 

be cancelled, so no CO2 capture is expected by 2010. The DF-Carson project may 

not startup by 2011 as planned. DOE has indicated that it plans to revise the 

FutureGen project so CO2 storage will not take place until after 2012. In October 

2007, the DOE awarded the first three large scale carbon sequestration projects in 

the United States. The Plains Carbon Dioxide Reduction Partnership, Southeast ReVerDate Nov 24 2008 13:10 May 24, 2012 Jkt 074322 PO 00000 Frm 00068 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\74322.TXT SCOM1 PsN: JACKIE
65 

gional Carbon Sequestration Partnership, and Southwest Regional Partnership for 

Carbon Sequestration, will conduct large volume tests for the storage of one million 

or more tons of CO2 in deep saline reservoirs in the U.S. 

Table 2.—Select Existing and Planned CO2 Storage Projects as of Early 2007 

Project CO2 Source Country Start 

Anticipated amount injected by: 

2006 2010 2015 

Sleipner Gas. Proc. Norway 1996 9 MT 13 MT 18 MT 

Weyburn Coal Canada 2000 5 MT 12 MT 17 MT 

In Salah Gas. Proc. Algeria 2004 2 MT 7 MT 12 MT 

Snohvit Gas. Proc. Norway 2007 0 2 MT 5 MT 

Gorgon Gas. Proc. Australia 2010 0 0 12 MT 

DF–1 Miller Gas U.K. 2009 0 1 MT 8 MT 

DF–2 Carson Pet Coke U.S. 2011 0 0 16 MT 

Draugen Gas Norway 2012 0 0 7 MT 

FutureGen Coal U.S. 2012 0 0 2 MT 

Monash Coal Australia N/A 0 0 N/A 

SaskPower Coal Canada N/A 0 0 N/A 

Ketzin/CO2

STORE N/A Germany 2007 0 50 KT 50 KT 

Otway Natural Australia 2007 0 100 KT 100 KT 

Totals 16 MT 35 MT 99 MT 

Source: Sally M. Benson (Stanford University GCEP), ‘‘Can CO2 Capture and Storage in Deep Geological 

Formations Make Coal-Fired Electricity Generation Climate Friendly?’’ Presentation at Emerging Energy Technologies Summit, UC Santa Barbara, California, February 9, 2007. [Note: Statoil has subsequently suspended 

plans for the Draugen project and announced a study of CO2 capture at a gas-fired power plant at 

Tjeldbergodden. BP and Rio Tinto have announced the coal-based ‘‘DF–3’’ project in Australia.] 

Enhanced Oil Recovery. Experience relevant to CCS comes from the oil industry, 

where CO2 injection technology and modeling of its subsurface behavior have a proven record of accomplishment. EOR has been conducted successfully for 35 years in 

the Permian Basin fields of west Texas and Oklahoma. Regulatory oversight and 

community acceptance of injection operations for EOR seem well established. 

Although the purpose of EOR heretofore has not been to sequester CO2, the practice can be adapted to include large-volume residual CO2 storage. This approach is 

being demonstrated in the Weyburn-Midale CO2 monitoring projects in Saskatchewan, Canada. The Weyburn project uses captured and dried CO2 from the Dakota 

Gasification Company’s Great Plains synfuels plant near Beulah, North Dakota. The 

CO2 is transported via a 200-mile pipeline constructed of standard carbon steel. 

Over the life of the project, the net CO2 storage is estimated at 20 million metric 

tons, while an additional 130 million barrels of oil will be produced. 

Although EOR might help the economics of early CCS projects in oil-patch areas, 

EOR sites are ultimately too few and too geographically isolated to accommodate 

much of the CO2 from widespread industrial CO2 capture operations. In contrast, 

saline formations are available in many—but not all—U.S. locations. 

CCS in the United States 

A DOE-sponsored R&D program, the ‘‘Regional Carbon Sequestration Partnerships,’’ is engaged in mapping U.S. geologic formations suitable for CO2 storage. 

Evaluations by these Regional Partnerships and others suggest that enough geologic 

storage capacity exists in the U.S. to hold many centuries’ production of CO2 from 

coal-based power plants and other large point sources. 

The Regional Partnerships are also conducting pilot-scale CO2 injection validation 

tests across the country in differing geologic formations, including saline formations, 

deep unmineable coal seams, and older oil and gas reservoirs. Figure 11 illustrates 

some of these options. These tests, as well as most commercial applications for longterm storage, will use CO2 compressed for volumetric efficiency to a liquid-like 

‘‘supercritical’’ state; thus, virtually all CO2 storage will take place in formations at 

least a half-mile deep, where the risk of leakage to shallower groundwater aquifers 

or to the surface is usually very low. 

66 

5http://web.mit.edu/coal/The Future of Coal.pdf. 6 EPRI, Overview of Geological Storage of CO2, Report ID 1012798. 

After successful completion of pilot-scale CO2 storage validation tests, the Partnerships will undertake large-volume storage tests, injecting quantities of ∼1 million 

metric tons of CO2 or more over a several year period, along with post-injection 

monitoring to track the absorption of the CO2 in the target formation(s) and to 

check for potential leakage. 

The EPRI–CURC Roadmap identifies the need for several large-scale integrated 

demonstrations of CO2 capture and storage. This assessment was echoed by MIT in 

its recent Future of Coal report, which calls for three to five U.S. demonstrations 

of about 1 million metric tons of CO2 per year and about 10 worldwide.5 These demonstrations could be the critical path item in commercialization of CCS technology. 

In addition, EPRI has identified 10 key topics 6 where further technical and/or policy 

development is needed before CCS can become fully commercial: 

• Caprock integrity 

• Injectivity and storage capacity 

• CO2 trapping mechanisms 

• CO2 leakage and permanence 

• CO2 and mineral interactions 

• Reliable, low-cost monitoring systems 

• Quick response and mitigation and remediation procedures 

• Protection of potable water 

• Mineral rights 

• Long-term liability 

Figure 12 shows that EPRI’s recommended large-scale integrated CO2 capture 

and storage demonstrations is temporally consistent with the Regional Partnerships’ 

‘‘Phase III’’ large-volume CO2 storage test program. EPRI believes that many of the 

storage demonstrations should use CO2 that comes from coal-fired boilers to address 

any uncertainties that may exist about the impact of coal-derived CO2 on its behavior in underground formations. 


409novak13.eps
67 

7http://www.iogcc.state.ok.us/PDFS/CarbonCaptureandStorageReportandSummary.pdf. 8http://www.epa.gov/safewater/uic/pdfs/guideluiclcarbonsequestrationlfinal-03-07.pdf. 

CO2 Transportation 

Mapping of the distribution of potentially suitable CO2 storage formations across 

the country, as part of the research by the Regional Partnerships, shows that some 

areas have ample storage capacity while others appear to have little or none. Thus, 

implementing CO2 capture at some power plants may require pipeline transportation for several hundred miles to suitable injection locations, possibly in other 

states. Although this adds cost, it should not represent a technical hurdle because 

long-distance, interstate CO2 pipelines have been used commercially in oilfield EOR 

applications. Economic considerations dictate that the purity requirements of coalderived CO2 be established so that the least-cost pipeline and compressor materials 

can be used at each application. From an infrastructure perspective, EPRI expects 

that early commercial CCS projects will take place at coal-based power plants near 

sequestration sites or an existing CO2 pipeline. As the number of projects increases, 

regional CO2 pipeline networks connecting multiple industrial sources and storage 

sites will be needed. 

Policy-Related Long-Term CO2 Storage Issues 

Beyond developing the technological aspects of CCS, public policy needs to address 

issues such as CO2 storage site permitting, long-term monitoring requirements, and 

post-closure liability. CCS represents an emerging industry, and the jurisdictional 

roles among Federal and state agencies for regulations and their relationship to private carbon credit markets operating under Federal oversight has yet to be determined. 

Currently, efforts are under way in some states to establish regulatory frameworks for long-term geologic CO2 storage. Additionally, stakeholder organizations 

such as the Interstate Oil and Gas Compact Commission (IOGCC) are developing 

their own suggested regulatory recommendations for states drafting legislation and 

regulatory procedures for CO2 injection and storage operations.7 Other stakeholders, 

such as environmental groups, are also offering policy recommendations. EPRI expects this field to become very active soon. 

A state-by-state approach to sequestration may not be adequate because some 

geologic formations, which are ideal for storing CO2, underlie multiple states. At the 

Federal level, the U.S. EPA published a first-of-its-kind guidance (UICPG #83) on 

March 1, 2007, for permitting underground injection of CO2.8 This guidance offers 

flexibility for pilot projects evaluating the practice of CCS, while leaving unresolved 

the requirements that could apply to future large-scale CCS projects. 

Long-Term CO2 Storage Liability Issues 

Long-term liability for injected CO2 will need to be assigned before CCS can become fully commercial. Because CCS activities will be undertaken to serve the public good, as determined by government policy, and will be implemented in response 

to anticipated or actual government-imposed limits on CO2 emissions, a number of 

policy analysts have suggested that the entities performing these activities should 

be granted a measure of long-term risk reduction assuming adherence to proper procedures during the storage site injection operations and closure phases. 

RD&D Investment for Advanced Coal and CCS Technologies 

Developing the suite of technologies needed to achieve competitive advanced coal 

and CCS technologies will require a sustained major investment in RD&D. As 

shown in Table 3, EPRI estimates that an expenditure of approximately $8 billion 

will be required in the 10-year period from 2008–2017. The MIT Future of Coal re- port estimates the funding need at up to $800–$850 million per year, which apVerDate Nov 24 2008 13:10 May 24, 2012 Jkt 074322 PO 00000 Frm 00071 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\74322.TXT SCOM1 PsN: JACKIE

409novak14.eps
68 

proaches the EPRI value. Further, EPRI expects that an RD&D investment of 

roughly $17 billion will be required over the next 25 years. 

Investment in earlier years may be weighted toward IGCC, as this technology is 

less developed and will require more RD&D investment to reach the desired level 

of commercial viability. As interim progress and future needs cannot be adequately 

forecast at this time, the years after 2023 do not distinguish between IGCC and PC. 

Table 3.—RD&D Funding Needs for Advanced Coal Power Generation Technologies with CO2

Capture 

2008–12 2013–17 2018–22 2023–27 2028–32 

Total Estimated RD&D 

Funding Needs $830M/yr $800M/yr $800M/yr $620M/yr $400M/yr 

(Public + Private Sectors) 

Advanced Combustion, CO2

Capture 25% 25% 40% 

Integrated Gasification 80% 80% 

Combined Cycle (IGCC), 50% 50% 40% 

CO4 Capture 

CO2 Storage 25% 25% 20% 20% 20% 

By any measure, these estimated RD&D investments are substantial. EPRI and 

the members of the CoalFleet for Tomorrow program, by promoting collaborative 

ventures among industry stakeholders and governments, believe that the costs of 

developing critical-path technologies for advanced coal and CCS can be shouldered 

by multiple participants. EPRI believes that government policy and incentives will 

also play a key role in fostering CCS technologies through early RD&D stages to 

achieve widespread, economically feasible deployment capable of achieving major reductions in U.S. CO2 emissions. 

Senator KERRY. Thanks, Mr. Novak. 

I want to welcome Senator Stevens here. As I mentioned, Senator Stevens and I have joined together to introduce a commercialscale, both capture and sequestration effort here, which, I personally think in light of the testimony we’ve heard would be very important to have funded as rapidly as possible. 

Let me just ask this threshold question. Is there anybody at the 

table who has testified who does not accept the IPCC reports and 

the fundamental science of anthropogenic contribution to climate 

change? 

So, every one of you accept that science. Is there anybody who 

differs with the urgency expressed in the most recent reports about 

the levels of greenhouse gases that we can emit before we reach a 

tipping point, i.e., two degrees, 450 parts per million? OK. 

Yes, Doctor? 

Dr. MARBURGER. Yes, I wouldn’t accept that at face value, I think 

the concept of a tipping point is controversial. 

Senator KERRY. Do you believe there is a greenhouse gas standard which you believe raises alarm bells? Do you think we can go 

the 609 parts per million that we are heading to at the current 

rate? 

Dr. MARBURGER. In my mind, the current emission rates raise 

alarm bells. 

Senator KERRY. The current rates do? So, in other words, you’re 

arguing from the point of view that it is possible that that may be 

generous? That the 450 may be generous, that it may be less than 

that before you reach tipping point? 

69 

Dr. MARBURGER. It’s not clear to me whether there is a tipping 

point. It is clear that there is a anthropogenic impact on the climate, that if let go without action, will cause unacceptable impacts—— 

Senator KERRY. Fair enough, let’s work with that, at least. 

If you accept, as everybody has indicated, the fundamentals, 

here, then what Mr. Hawkins has suggested, which I have, actually 

put into legislation. We should not build one pulverized coal-fired 

power plant that does not now move toward some variant of what 

has been talked about here, the IGCC, gasification, etc., because 

otherwise, we are digging the hole deeper, are we not? 

Dr. Marburger? 

Dr. MARBURGER. It would be highly desirable to make sure that 

new coal-fired power plants have the capacity for retrofitting with 

carbon capture and storage as that technology becomes widespread. 

Senator KERRY. Are we, in fact, building power plants that are 

retrofittable in all circumstances today? 

Anybody? Mr. Hawkins? 

It’s my understanding that we’re building some pulverized coalpowered power plants that are just the old technology. They are 

not necessarily set up for retrofit? 

Mr. HAWKINS. Yes, I participated as an advisor to the MIT Coal 

Study that was released last year, and one of the things that they 

pointed out correctly, is that while a gasification plant that is built 

without capture is cheaper to retrofit than a pulverized coal plant, 

retrofitting either of them is a pretty expensive proposition. It is 

much better to build the plant with that capture equipment from 

the start and there is no reason to avoid doing that. We have the 

technology to do it. The challenges are a matter of economics and 

we have policies that can overcome the economic hurdles. We 

should get on with it. 

Senator KERRY. Mr. Novak, you’re nodding your head. 

Mr. NOVAK. It looks, in our opinion, you can retrofit some of 

these plants, it depends on—— 

Senator KERRY. When you say our opinion, just for the record, 

say it again. 

Mr. NOVAK. The Electric Power Research Institute. You can retrofit plants that are being built today, it’s a question of space, the 

ability to fit those plants, and can you get that CO2 that you capture to a storage site? That’s another question you’d have to—to 

pipe it. There’s no question, it will cost money to do that, and especially a pulverized coal plant, you’re talking about a 30 percent reduction, a 30 percent energy penalty, that much less electricity. 

Senator KERRY. Well, I agree that this question of cost on the 

piping is a big question, and in some parts of the country it’s going 

to be far more economical and feasible than in other parts of the 

country. 

Is there a distinction here as to whether or not you ought to 

allow a power plant, if they can’t pipe economically, or do you make 

some provision for that piping? What’s the approach here? 

Mr. NOVAK. I think that—looking at what the European Union 

is doing, they’re—they have a directive that is asking all new coal 

plants to be—to be ‘‘capture ready,’’ to have the space, to have the 

ability to fit, and to do an assessment of the ability to transport 

70 

and store that CO2 to some location. So that’s—that’s one option 

that one could consider for new plants. 

Senator KERRY. Now Dr. Strakey, I’d like to try to pin down 

where we are in terms of the FutureGen project. Obviously the initial flurry was that this was being abandoned. I mean, that was 

the announcement, we’re abandoning the FutureGen project as we 

know it. And now we talk about it as a restructuring. I’m a little 

confused, and obviously Mr. Mudd is concerned at the moment 

about a 5-year delay and other potential here. 

So, can you clarify for the Committee, where do we stand, specifically with respect to the Department’s efforts in the FutureGen sector and what is the status of FutureGen today? 

Dr. STRAKEY. OK, as you know, the Department was very concerned about the cost growth in FutureGen project, and we thought 

that going forward with the FutureGen project as it was originally 

proposed, presented unacceptable financial risk in terms of cost escalation. 

And as a result, we started—going back to late last fall—looking 

at other alternatives to try to accomplish the same thing in a reasonable time-frame. 

And the situation, since FutureGen started has changed. Right 

now, we have a number of plants that are anticipated being built, 

but they’re faced with a dilemma. Can they build it with carbon 

capture? They don’t know. And I think they would be willing to 

build coal plants equipped with carbon capture if the government 

helps finance that part of the project. 

In addition, one of the reasons that they can’t build them is because they’re facing permit obstacles, and we’ve seen that in a 

number of states projects have been cancelled or moved, as a result 

of these permit issues. If they have carbon capture equipment 

available there, they might be able to get past their permit issues 

and get these plants built. 

Senator KERRY. It seems like there’s a contradiction in that. If 

they have it, they can then be built. The whole idea was that you 

were going to help them have it. And in your testimony, your written testimony, you say gasification technology holds substantial 

promise as the best coal conversion technology option to utilize carbon capture technologies. 

So, if that’s the case, why has the Federal Government reduced 

its commitment, or abandoned its commitment to IGCC with CCS 

by dropping the FutureGen project? Isn’t that the best way to get 

everybody permitted and up and most rapidly bring this to conclusion? 

Dr. STRAKEY. We believe that by changing to the revised 

FutureGen or FutureGen restructured—we also called it plan B— 

then we’ll be able to have multiple demonstrations, and they will 

come online about 2 years later. But they will finish in about the 

same time-frame, maybe a little bit later, but that will lead to the 

next wave of commercial plants in a quicker manner. 

Senator KERRY. So, Mr. Mudd, what’s your reaction to that? Why 

do you believe there’s a 5-year delay? Obviously you disagree, and 

what’s the downside? 

Mr. MUDD. Mr. Chairman, it takes a long time for the U.S. Government, appropriately so, to come up with a Request for ProVerDate Nov 24 2008 13:10 May 24, 2012 Jkt 074322 PO 00000 Frm 00074 Fmt 6633 Sfmt 6601 S:\GPO\DOCS\74322.TXT SCOM1 PsN: JACKIE
71 

posals, to receive the bids, to negotiate the contract, and then to 

award the contract, and then to do the design and cost estimate for 

it. And then there’s also a program rule that says you can not 

begin procurement or the detailed design until you have met all the 

NEPA requirements, gotten the environmental impact statement. 

Typically, it takes 2 to 3 years at best to get the EIS. Now we’re 

very fortunate because of the phenomenal amount of work that was 

done in advance, to the get the environmental impact statement— 

as a credit to the hard working employees of the Department of Energy—to get that done in approximately 14 to 16 months. 

Now having said that, if we look at—right now you start with the 

new program today, and then what is the earliest—and one can 

ask the questions and conjecture—when’s the earliest that the bids 

would come in to the Department of Energy, what’s the earliest 

that the DOE could award the contracts, and then do the preliminary design, and then do the EIS, and then, at that point, be able 

to procure the equipment in the face of increasing escalation to 

these prices, with the expectation that the cost will go down? I 

think these are some severe challenges that one would look at, and 

I believe that it would be 5 years, basically, before the DOE, before 

a participant would be in the position to even begin to procure the 

equipment, based on that. 

Senator KERRY. Dr. Strakey? 

Dr. STRAKEY. I would say that we are very close to having a solicitation ready to go out on the street. 

Senator KERRY. Well, how about how long does it take once 

you’ve done that? 

Dr. STRAKEY. Mr. Mudd said that that it would take 3 years to 

do the NEPA process, and I think we—in working through 

FutureGen—we cut that time in half. So, I think that our estimates are a little more optimistic about when the plants would 

come online than Mr. Mudd’s. 

Senator KERRY. Mr. Childress or Mr. Hawkins, anybody? 

Dr. STRAKEY. But it will be after the original date. 

Senator KERRY. Mr. Hawkins? 

Mr. HAWKINS. This cancellation or restructuring is clearly going 

to result in a delay. I think the proof is in the pudding. It took 5 

years to get from the announcement—— 

Senator KERRY. Do you agree there will be a delay, Dr. Strakey? 

Dr. STRAKEY. Yes. 

Senator KERRY. Why is that acceptable? 

Dr. STRAKEY. Because we think by having a multiple demonstrations, it will convince the commercial sector to move more rapidly, 

and that they’ll be prepared to take that next step for a number 

of commercial plants faster. 

Senator KERRY. Mr. Hawkins? 

Mr. HAWKINS. Again, if we enacted bills that are getting serious 

consideration in Congress, we’ll have multiple demonstrations, and 

we do not need to wait for a new set of authorizations, a new set 

of appropriations, a new Administration. 

The truth is that this restructuring is handing it off to the next 

Administration. This Administration is not going to do anything, 

rather than, maybe get a solicitation out the door, possibly get 

72 

some responses to that solicitation at the time they’re leaving office. 

This doesn’t make any sense. We need a faster acting relief package. 

Senator KERRY. Well, we’ll come back to it. 

Senator Ensign? 

Senator ENSIGN. Thank you, Mr. Chairman. 

Obviously there’s a difference of opinion depending on where you 

sit. If we had unlimited funds, we would fund the FutureGen plant 

and fund the other ones that would be proving other technology at 

the same time, moving on a dual-track process, so that we could 

have other commercial technologies come onboard. 

But I do want to ask you this question. Because of the different 

types of coal that we have in the United States, if you had just the 

one FutureGen plant, wouldn’t that leave out half of the United 

States, Mr. Mudd? 

Mr. MUDD. Senator Ensign, the FutureGen project is being designed to be able to address more than the eastern bituminous coal. 

We do recognize that there are efficiency and cost penalties associated with the other coals, and it’s an issue that absolutely must be 

solved. And the way the FutureGen has been designed is to be able 

to address those penalties associated with the different types of 

coals and be able to test the different types of coals. 

With respect to the carbon sequestration itself, while there are 

different geologic formations, there are important common parts, 

including the liability, the permitting, the mineral rights, and so 

on. The Alliance spent over $1.5 million of both—of the project 

funds, both private funds and government funds, in addressing the 

legal issues associated with injecting CO2. It’s not a trivial matter 

to identify the mineral rights, negotiate them, and be able to prepare to inject in those areas. Those are common regardless of 

where you built it. 

Senator ENSIGN. Correct. 

Except, Dr. Strakey, maybe you could address this. The western 

United States is growing rapidly and our electricity demands are 

growing rapidly as well. My home State and Arizona are some of 

the fastest growing states in the United States. 

With FutureGen and the significant problems that you have just 

identified, Mr. Mudd, it would seem to me that if we need power 

plants in the future, we’re going to be much farther behind as far 

as clean coal, carbon capture, and sequestration technologies in the 

West than the East would be. Because of that, we coulbe be at a 

significant disadvantage. 

You have mentioned some of the commonalities, but there are 

significant differences also in storage. Because we are not just looking at how you can store it, but what are the effects of storing it. 

I believe we must study this over several years. Isn’t that correct? 

Dr. STRAKEY. Yes, that is correct. And one of the things we’re 

looking at in the Carbon Sequestration Regional Partnerships, is 

doing some large volume injection tests around the country so we 

get some idea of the storage capability and what the issues are 

with different formations. 

I would also add that there is an advantage having multiple 

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ern and eastern coals, because whichever gasifier you choose, it’s 

really going to be optimized for one particular coal. And although 

you can test different coals in that gasifier, as was planned in 

FutureGen originally, it’s not the same as having the information 

on optimized gasifiers for each coal. 

Senator ENSIGN. If we were to go with what I mentioned, a dualtrack approach, what the Administration has proposed, as well as 

keeping the FutureGen plant, does anybody know how much that 

would cost? Are we talking about doubling the cost or are we talking 21⁄2 times or 11⁄2 times? Does anybody have any idea? 

Dr. STRAKEY. Well, our estimate for the restructured FutureGen 

would be in the order of $300 to $600 million per project, of Federal 

funds. And I think the Federal funds in FutureGen original project 

is about $1.3 billion remaining. 

Senator ENSIGN. How much of that has already been spent? Has 

most of that already been spent on the FutureGen plant? 

Dr. STRAKEY. No, a very small amount—— 

Senator ENSIGN. OK. 

Dr. STRAKEY. We’re in the design stage. 

Senator ENSIGN. OK. 

Dr. STRAKEY. Very small. 

Mr. MUDD. To date, the funds have been about $40 million in 

government money and $10 million in private money on 

FutureGen. 

Senator ENSIGN. OK, so we are talking approximately double if 

you are doing four or five of these demonstration projects. You are 

looking at probably doubling the amount of money then, correct? 

Dr. STRAKEY. We’re thinking, for the same $1.3 billion, we might 

get two to four additional demonstrations. 

Senator ENSIGN. OK. 

Thank you, Mr. Chairman. That’s all the questions that I have. 

Senator KERRY. Thank you very much. 

Let me just pin down a few things here and then we can hopefully wrap up. 

Mr. Hawkins, what level of capture do we need to achieve from 

coal-fired power plants? 

Mr. HAWKINS. Well, over the long term, we really have to get as 

much carbon out of the power plants as possible. Right now we 

think that it’s feasible to do 85 to 90 percent. Our view is based 

on the history of things like SO2 scrubber technology, that as these 

systems get deployed, they’ll be optimized and will do better and 

better. 

And, our view is that we can expect to have commercially operating capture systems that are in the mid-90s or possible even 

higher, but we won’t start there. We’re probably going to start, you 

know, with something less than that, but the important thing is to 

get the initial ones deployed, get the operating experience, and 

then allow the next designs to build on that operating experience. 

Senator KERRY. Dr. Strakey, originally you had a 90 percent capture requirement on the Mattoon, correct? 

Dr. STRAKEY. That’s correct. 

Senator KERRY. Will that be transferred down to these other facilities? 

74 

Dr. STRAKEY. We’re still considering that. In the public comments that we had on the draft Request for Information, there 

were quite a few comments that we should lower that and perhaps 

we may lower it. 

Senator KERRY. Why would you lower it, given the increased 

science and the fact that you’ve already imposed that, previously? 

Dr. STRAKEY. I think when you get to around 85 percent or in 

that neighborhood, for certain gasifiers, especially the ones that 

produce a little bit of methane, it’s very difficult and expensive to 

get from 85 to 90. So, there’s some kind of economic breakpoint 

around there, but generally—— 

Senator KERRY. But absent some indication that we can tolerate 

that additional percentage of emission, don’t we have to? 

Dr. STRAKEY. I’m sorry? 

Senator KERRY. Well, absent some indication that you can get by 

with 85 percent, don’t you have to set the 90 percent and don’t you 

have to meet the standard that science tells you you’ve got to reduce? 

Dr. STRAKEY. Well, I think in the long run, you may even have 

to go above 90. 

Senator KERRY. I agree, which is why I’m wondering why we’re 

going below 90. 

Dr. STRAKEY. Because it’s an economic—it’s better—— 

Senator KERRY. Economics don’t work out in the far run and on 

the mitigation. 

Dr. STRAKEY. I would also add one other important point. 

Senator KERRY. Let me just finish that, though. The economics 

are miserable if you’ve got to move millions of people and the insurance industry walks away from insuring people, and shorelines 

change, and you’re spawning grounds disappear, and vegetation 

migrates north, and a whole bunch of other things happen. You 

want to talk about costs, factor in the cost of not doing this. 

Dr. STRAKEY. I understand that. 

Senator KERRY. But are you really translating it into the policy? 

Dr. STRAKEY. I think you have options, also. If you build a plant 

that’s, say, 85 to 90 percent now, to increase that later, either 

through just changes to the process itself or more importantly, 

through introduction of biomass into the coal gasification plant 

itself. And in situations like that, some of our studies show you can 

go net-carbon negative. Now that’s relatively new, but that may be 

a very attractive option for converting some of these plants later 

on to even higher—— 

Senator KERRY. But will you do that if you don’t set the standard? It’s like kids with their homework, if you don’t tell them when 

it’s due, it doesn’t get done. 

Dr. STRAKEY. I’m not sure about that one, but we think that, you 

know, 85 percent is a heck of a lot better than what you have now 

and what a lot of people are considering. 

And by the way, the back-up, the default option here is, if we do 

nothing, we’ll be burning natural gas and that has carbon in it. 

And at some point, we’re going to have to take that out. So if we 

shift the economy to heavier reliance on natural gas, we’ll pay the 

price for that later. And it may be even worse. 

75 

Senator KERRY. I’m not for that. I don’t disagree with you. But 

as someone pointed out earlier, we don’t have the reserves and the 

demand is not going to allow that to happen anyway. You look at 

the demand curve in China today, let alone other countries. I 

mean, that’s a nonstarter. 

Dr. STRAKEY. I agree. 

Senator KERRY. Well—— 

Dr. STRAKEY. By the way, we have not actually made a determination of what the level would be, whether it would be 80, 90, 

whatever. 

Senator KERRY. Well, I urge you, given the givens here, to really 

take a hard look at the facts as they’ve been laid out and as the 

scientists have laid them out and what the demand is. I think it 

would be a huge mistake to move backward on that standard, given 

the unbelievable amount of science that is now accruing. Most recently the Arctic, Antarctic ice break-off and what we’re seeing. 

Every bit of feedback there is, is coming back faster and greater 

than was predicted. Cautious people, it seems to me, would take 

that evidence and process it appropriately. 

Mr. CHILDRESS. Senator, if I might add one item here. We’re getting very, and importantly so, focused on FutureGen as a Federal 

program. I can say this categorically, I know of no publicly announced IGCC in the United States that’s prepared to move forward with CCS, the economics are not there. And in the absence 

of a program—I don’t want the headlines to say ‘‘Jim Childress 

agrees with Dave Hawkins on everything,’’ but in the absence of a 

program that provides regulatory certainty, and addresses liability 

issues, Mr. Hawkin’s cost sharing scheme may or may not work for 

anybody. But you’ve got to have some way to cost share so that 

those projects that are going to cost more, we know that, can move 

forward financially, can get the investors necessary to do it. 

In the absence of this, what we’re seeing is a cluster of gasification projects on the Gulf Coast. It’s the industrial gasification I 

talked about. And, it’s for chemicals, for fertilizers, even TXU, 

former TXU, now Illuminate, is looking at, has not announced publicly, some potential IGCCs, but they have a carbon sink, which is 

enhanced oil recovery, where you make money. Instead of spending 

money to put it in the ground, you’re going to make money. 

Just a couple of days ago a project was announced in Louisiana, 

producing substitute natural gas. Denberry Resources has committed to buy that CO2 for enhanced oil recovery, and they floated 

a big GO Zone Bond, $1.1 billion bond. That is a package that 

makes sense, but it comes together because somebody will pay you 

for the CO2 and it’s not an added cost to capture it and put it in 

the ground. 

Senator KERRY. Mr. Novak, there are a limited number of IGCC 

plants with CCS I know, how many do you know of? 

Mr. NOVAK. IGCC with CCS? None. 

Senator KERRY. None at all. 

Mr. NOVAK. There are lots of gasification, industrial gasification 

plants that capture—— 

Senator KERRY. The North Dakota one doesn’t include both IGCC 

and CCS? 

76 

Mr. NOVAK. That’s a gas—industrial gasification facility that captures CO2 and produces—and pipes that CO2 to Canada. 

Senator KERRY. It produces it for use in enhanced oil recovery? 

Mr. NOVAK. That’s correct. 

Senator KERRY. It’s not, OK. 

Mr. NOVAK. It produces gas, it’s a gas—— 

Senator KERRY. Right, so it has capture of it, no storage. 

Mr. NOVAK. It has capture, but no power generation. 

Senator KERRY. Right. Oh, OK. I see, and the combined cycle 

component of it. 

Mr. NOVAK. Right. And it ships it to Canada and then Canada 

pays it for the CO2. That’s—— 

Senator KERRY. Right. 

Mr. NOVAK.—that’s the economic difference. 

Senator KERRY. How many different locations are we using it for, 

the EOR? 

Mr. HAWKINS. There are about 70 projects, most of them in the 

United States, a few outside the United States, but we have a couple of—— 

Senator KERRY. We’ve been doing that for a long time, haven’t 

we? 

Mr. HAWKINS. Yes, since the 1970s, and we’re currently injecting 

something on the order of 35 million tons of CO2 a year into these 

formations. Unfortunately, about 80 percent of that is pulled out of 

other natural CO2 reservoirs, so we’re not actually getting—— 

Senator KERRY. Right, I realize that. 

Mr. HAWKINS.—abatement. 

Senator KERRY. I know we’re taking it from natural CO2, I realize that. 

Mr. HAWKINS. But we do have lots of experience with massive 

amounts of geologic CO2 injection, not quite as large as will come 

out of a typical power plant, but large enough to demonstrate that 

we know how to handle these high pressure gases in very large 

quantities, and do it safely. 

Mr. NOVAK. But I would suggest that we do need to do some 

tests in geologic formations, in these deep aquifers or saline formations to show that we know what happens to that CO2 when 

we—— 

Senator KERRY. Oh, sure we do. I couldn’t agree more and I testified recently, before the Energy Committee, because I have a regulatory protocol that we’ve put together that we need to get in place. 

People have got to know what the standards are going to be, 

what’s the liability going to be, what are the rules going to be, how 

does this work? We’ve got to get that out there. I think that’s urgent. As urgent as anything else to encouraging people to know the 

rules they’re playing by, which is important when you’re dealing 

with money. People are going to have to have a sense of that. 

Mr. HAWKINS. It is important to note that in addition to the enhanced oil recovery activities, we have a couple of fairly long-running projects that are injecting CO2 into these other types of formations. One under the North Sea that began in 1996, it’s under the 

seabed in a—in a saline aquifer formation. And another one in Algeria that is associated with a gas field, but it’s not used for enhanced oil recovery, it’s permanent storage. 

77 

Senator KERRY. Mr. Novak, do you have any sense of the level 

and sort of structure that the the electro-power industry, might put 

into the deployment of CCS technology? 

Mr. NOVAK. Senator, we’ve done an analysis that looks at, if we 

had to meet a future climate constraint, and we put one into a 

model, and we put in cost and performance data for the alternatives, for energy efficiency, renewable, coal with capture and 

storage, nuclear power, natural gas, and a large portion of that future generation would come from CO2, coal with CO2 capture and 

storage, and nuclear. Those are the two largest ones, based on 

straight economics. 

Senator KERRY. What about if a cap and trade were to pass here, 

and we were to put that into effect. Would that speed up the application of IGCC technology with CCS? 

Mr. NOVAK. Senator, it would clearly move up—it could impact 

deployment because then there’s a price of carbon. You don’t—you 

wouldn’t capture and store carbon unless there’s a reason to do so. 

There’s no economic reason to capture and store CO2. You either 

need a cap that puts a price on carbon, a carbon tax that puts a 

price on carbon, a mandate, or a tax credit, for example, that would 

make it economic for you to capture and store CO2. I think the big issue in timing, Senator, is proving storage. It 

takes three to 5 years to build a facility, three to 5 years to inject, 

three to 5 years to monitor. We’ve got to get those tests underway 

and done. Unless we use CO2—we can use CO2 from existing 

sources and maybe move that storage test up and the regional 

partnerships are doing that. But we need to get these large-scale 

demonstrations. 

We also need to build IGCC with capture and storage to show we 

can capture it and we can burn hydrogen at full scale in a combined-cycle turbine and reliably generate electricity. We need to do 

pulverized coal. 

Senator KERRY. How widespread is the storage? I mean, the storage concept? Conceptually we know it works already, don’t we? As 

we just said, we’re taking natural storage centers and using them, 

so it’s been stored. And if we’re taking it out of there, I assume we 

can put it in there. 

Mr. MUDD. Senator Kerry, though, I want to underscore that you 

can look at any of the components of a plan—of carbon capture and 

sequestration, and the gasification, and IGCC, and see how bits 

and pieces have been proven throughout the world. What has not 

been done is the total integration of all of these complex systems. 

Senator KERRY. I completely agree and I understand, which is 

why I introduced the legislation to get a commercial-scale project 

out there. 

Here’s the way I see it. There are certain saline aquifers, other 

areas where we don’t know how air tight it is, we don’t know 

whether it’s going to leak, et cetera. There are some places where 

you’ve obviously got to test it. But in theory and in principal, we 

know that there are existing caverns or cisterns where, for years, 

something was contained in there, in a non-releasable form, until 

we drilled in and opened it up. 

Mr. NOVAK. I think the work that’s done under the Department 

of Energy Regional Partnerships work has done an atlas of geologic 

78 

storage formation. They look like they—they appear to be widespread throughout the U.S., not in every State, but a lot of potential capacity. The phrase, ‘‘We are the Saudi Arabia of coal, we are 

the Saudi Arabia of storage capacity in the world.’’ We have 

enough, I think, as one of the other witnesses testified, but we need 

to do some site-specific tests for those geologic formations, in those 

regions to make sure that it’s sound and it’s suitable—— 

Senator KERRY. Right, I understand. 

Mr. NOVAK.—and do the tests. 

Senator KERRY. I understand that. 

When you talked about a zero emission or a net negative emission, is that only achievable factoring in the storage? Could you do 

that without storage? 

Dr. STRAKEY. No, storage is an essential part of that. 

Senator KERRY. It’s critical. There’s no other theory about how 

you take the CO2 and dispose—— 

Dr. STRAKEY. That’s right. Essentially, with this extra increment, 

you’re capturing CO2 from the atmosphere and storing it geologically through—— 

Senator KERRY. So what’s the best estimate, from a policy point 

of view, as to how much CO2, and for how long can we do that? 

I mean, there are limits ultimately to how much you’re going to be 

able to capture. Is this geared to the ultimate weaning of fossil 

fuels altogether? Or is it geared as some earlier date, in effect, because of the limits on storage itself? How long do we get the economic benefit of this, and does that amortize out adequately? 

Mr. CHILDRESS. The DOE puts a range of 200 to 500 years given 

current generating capacity in the U.S. And importantly, most of 

that, 90 plus percent of that, is saline aquifers. Enhanced oil recovery is the low-hanging fruit today, that’s why everybody’s being attracted to that. But the silver bullet is saline aquifers, which is 

why, personal opinion, we certainly need one or more IGCCs with 

CCS injecting into saline aquifers. 

Dr. STRAKEY. Senator Kerry? 

Senator KERRY. Yes, sir. 

Dr. STRAKEY. If I could add to that. Our estimate for storage in 

saline aquifers, the upper estimate was on the order of 500 years. 

For enhanced oil recovery there’s capacity for about 83 gigatons. At 

current emissions from North America, that would be about 12 

years. 

Mr. HAWKINS. Senator, if I might just add our own view. Capacity is not the constraint, there is adequate capacity. Technology is 

not the constraint, nor is understanding of feasibility the constraint. Both the IPCC and the MIT study concluded that we know 

enough about the geology of these formations to safely store millions of tons a year in individual projects. 

What the demonstrations will accomplish is getting hands-on experience out of the oil industry and into the power sector industry. 

The oil industry knows how to do this stuff. The oil industry understands the geology. This is not a question of sort of experimenting 

and sticking a well in somewhere and saying, ‘‘Well gee, now we’ll 

see whether it works or not.’’ When that well is drilled, the companies that operate it will know the CO2 is not going to leak out. The 

79 

pathways that are the most risky are other wells that have been 

drilled into the formation because they form a potential pathway. 

So, the understanding is very clear. What the industry will do 

before going into a formation is they’ll do a survey, they’ll find that 

the cap rock is thick, they will survey the cap rock to make sure 

that there are no natural fractures or faults that could be a pathway, and then they will survey the location of any wells, and evaluate the integrity of the cement to make sure that it can not become 

a pathway. This is well understood as to what needs to be done. 

So, this is not a matter of guesswork. 

Senator KERRY. So, what in your judgment, what’s the delay factor here, in your judgment, Mr. Hawkins? Why aren’t we moving 

full speed ahead? 

Mr. HAWKINS. Well, we have frankly been schizophrenic about 

the need to attack the global warming problem and we are now approaching the point where the U.S. is about to get serious in doing 

it. And, I think, you know, frankly, the industry has been schizophrenic as well, and all of that has lead to delay. 

But, I—Senator Ensign asked the question about how much 

would it cost to do a couple of these projects, and the answer was 

it, you know, might take $2 billion. 

But to put that in perspective, the kind of policies to cap and 

trade carbon dioxide emissions that are being discussed, will generate enormous amounts of resources that can be deployed to accelerate the deployment of this kind of technology. 

For example, in the Lieberman-Warner bill, there is a provision 

that provides subsidies for going ahead quickly with carbon capture 

and storage, and the funds in that provision alone are on the order 

of $3 to $5 billion a year for 10 years. 

Senator KERRY. It’s a big pot. Well, we’re trying to win some 

votes. 

Mr. Childress, what—you emphasized the need to develop these 

plants. What do you think would be the best support structure, 

how could we most rapidly accelerate this effort? 

Mr. CHILDRESS. The first thing that industry needs is predictability in public policy. The investment community needs the same 

thing. They have to know that there are rules out there and if they 

follow those rules and make a prudent investment, they will get a 

return. 

Now, we don’t have a price on carbon, it gets down to some sort 

of cost-sharing to get the first adopters in place. And it has to do 

with legal issues such as liability. Once you put that—— 

Senator KERRY. You would concur that cap-and-trade, in effect, 

is a pricing of carbon? 

Mr. CHILDRESS. I will say whatever puts a price on carbon, and 

if that price is such that it will convince investors, if they build an 

IGCC or and SNG plant with CCS; and, they will get a return, that 

will work. 

Senator KERRY. Understood. 

Well, this has been very helpful and I appreciate the creation of 

this record. Is there anything anybody feels they wanted to say 

that they haven’t had a chance to? It’s a wise panel. 

[Laughter.] 

80 

Senator KERRY. So I’m going to leave the record open for 2 weeks 

in case any of our colleagues want to submit any question to you 

in writing. And I’m very, very appreciative to you for taking time 

to come here today, helping us formulate this. We’ve got a long way 

to go and we’ve a very short time to do it, this has been helpful. 

Thank you. 

We stand adjourned. 

[Whereupon, at 4:08 p.m., the hearing was adjourned.] 

(81) 

A P P E N D I X 

PREPARED STATEMENT OF HON. TED STEVENS, U.S. SENATOR FROM ALASKA

Mr. Chairman, thank you for holding this hearing today on coal gasification. 

In the United States alone, coal-fired power plants satisfy more than half of the 

Nation’s energy needs and this percentage is likely to increase in the future. Coal 

is both abundant, inexpensive, and represents one of our most important natural 

resources. 

It is a stable commodity and a key component in satisfying the United States’ 

growing energy demands. Coal production is an important element to our national 

security. Without it, we would be increasingly reliant on unstable or unfriendly nations for our energy needs. 

Continued reliance on imported energy from volatile regions of the world is not 

a solution. We must increase our domestic production in order to remain globally 

competitive and we must do so in an environmentally responsible manner. 

New technologies to make this possible are on the horizon. Carbon capture and 

sequestration is just one of many processes already in development. Groundbreaking 

research is being conducted to develop new ways to burn coal in order to maximize 

energy yield and employ cleaner and more efficient processes. 

One of these processes is the Integrated Gasification Combined Cycle or IGCC. 

The IGCC process is a promising new technology, which has the potential to increase efficiency by 40 percent. 

However, I understand that this process is not conducive to all regions because 

of its limitations on the type of coal, which can be used. Solutions must be found 

that will accommodate the local needs and we must continue to research and develop other methods. 

I believe that in order to reduce our impact on the environment while still providing the energy necessary to fuel our economy, we must take steps to find a technological solution and make clean coal a reality. This is why I am a cosponsor of 

Senator Kerry’s clean coal demonstration bill. S. 2323 would require the Secretary 

of Energy to establish a competitive grant program to provide assistance for commercial demonstration projects for the capture and sequestration of carbon emissions from coal-fired power plants. 

As we move into the future, many different types of energy technology must be 

used in order for this Nation to remain competitive and secure. Coal will continue 

to be the backbone of our Nation’s energy supply, and we must develop ways to use 

it in an efficient and clean manner. 

I look forward to hearing today’s testimony. 

RESPONSE TO WRITTEN QUESTION SUBMITTED BY HON. JOHN F. KERRY TO

DR. JOSEPH P. STRAKEY, JR. 

Question. Could you please provide clarification on the analysis you mentioned 

during oral testimony in regards to the cost of implementing CCS nationwide by 

2030. 

Answer. National Energy Technology Laboratory (NETL) examined a United 

States policy scenario that applied a tax of $30 per metric ton of carbon dioxide from 

2015 to 2030. Projections were based upon cost and performance assumptions consistent with the U.S. Energy Information Administration’s 2007 Annual Energy 

Outlook. Cost and performance for retrofitting the existing fleet of pulverized coal 

(PC) power plants was based on a recent NETL study (Carbon Dioxide Capture from 

Existing Coal-Fired Power Plants, DOE/NETL–401/110907, revised November 2007). 

The analysis projected that 40 gigawatts (GW) of new advanced coal-fueled power 

plant capacity would be deployed with carbon capture and sequestration (CCS). It 

also projected that 100 GW of existing PC net power plant capacity would be retrofitted for CCS through 2030. However, the parasitic energy consumed by the CCS 

82 

equipment would reduce the total net output of these plants to 70 GW (a reduction 

of 30 GW-net). 

The cost of constructing 40 GW of new coal-fueled power plant capacity with CCS 

is estimated to be $140 billion (2007-year dollars), including owner’s costs but excluding allowance for funds used during construction. Twenty-eight percent, or $40 

billion, of the total construction cost is attributable to adding CCS. This estimate 

assumes that the new advanced coal plants are Integrated Gasification Combined 

Cycle (IGCC) plants with a capital cost of $3,500/kilowatt (kW), of which $970/kW 

is attributable to CCS. (If CCS was not applied to the 40 GW of new IGCC power 

plants, their net capacity would be increased by 15 percent, or 6 GW.) 

The ‘‘overnight’’ cost of retrofitting 100 GW of PC power plant capacity for CCS 

is estimated to be $95 billion (2007-year dollars). Retrofit costs ($955/kW of pre-retrofit capacity) were escalated from July–2006 dollars to October–2007 dollars using 

Chemical Engineering’s Plant Cost Index. If the resulting reduction in capacity (30 

GW-net) was replaced by new IGCC plants with CCS, the replacement cost would 

be $105 billion. 

The total cost of CCS for both the new and retrofitted capacity would be $240 billion (2007-year dollars). The avoided carbon dioxide emissions for the 40 GW of new 

IGCC amounts to approximately 189 million metric tons/yr; for the 100 GW of retrofitted PC plants, the avoided CO2 amounts to approximately 550 million metric tons 

per year (including the CO2 emitted by the 30 GW of IGCC replacement power 

equipped with CCS). 

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