[Senate Hearing 110-1130]
[From the U.S. Government Publishing Office]




                                                       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




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       SENATE COMMITTEE ON COMMERCE, SCIENCE, AND TRANSPORTATION

                       ONE HUNDRED TENTH CONGRESS

                             SECOND SESSION

                   DANIEL K. INOUYE, Hawaii, Chairman
JOHN D. ROCKEFELLER IV, West         TED STEVENS, Alaska, Vice Chairman
    Virginia                         JOHN McCAIN, Arizona
JOHN F. KERRY, Massachusetts         KAY BAILEY HUTCHISON, Texas
BYRON L. DORGAN, North Dakota        OLYMPIA J. SNOWE, Maine
BARBARA BOXER, California            GORDON H. SMITH, Oregon
BILL NELSON, Florida                 JOHN ENSIGN, Nevada
MARIA CANTWELL, Washington           JOHN E. SUNUNU, New Hampshire
FRANK R. LAUTENBERG, New Jersey      JIM DeMINT, South Carolina
MARK PRYOR, Arkansas                 DAVID VITTER, Louisiana
THOMAS R. CARPER, Delaware           JOHN THUNE, South Dakota
CLAIRE McCASKILL, Missouri           ROGER F. WICKER, Mississippi
AMY KLOBUCHAR, Minnesota
   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,        JOHN ENSIGN, Nevada, Ranking
    Chairman                         JOHN McCAIN, Arizona
JOHN D. ROCKEFELLER IV, West         KAY BAILEY HUTCHISON, Texas
    Virginia                         GORDON H. SMITH, Oregon
BYRON L. DORGAN, North Dakota        JOHN E. SUNUNU, New Hampshire
BARBARA BOXER, California            JIM DeMINT, South Carolina
MARIA CANTWELL, Washington           JOHN THUNE, South Dakota
MARK PRYOR, Arkansas
CLAIRE McCASKILL, Missouri
AMY KLOBUCHAR, Minnesota

                            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


  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.
    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, peer-reviewed 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.
    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.
    [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 state-of-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 removal 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 
Integrated-Gas-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 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 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 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.
    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\
---------------------------------------------------------------------------
    \1\ Energy Information Administration, International Energy Outlook 
2007, www.eia.doe.gov/oiaf/ieo/emissions.html.
---------------------------------------------------------------------------
    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 sequestration 
(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\
---------------------------------------------------------------------------
    \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).
---------------------------------------------------------------------------
    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.
---------------------------------------------------------------------------
    \3\ AEO2008 Revised Early Release (available at http://
www.eia.doe.gov/oiaf/aeo/excel/aeotab_18.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]
    \5\ http://www.eia.doe.gov/oiaf/aeo/excel/aeotab_9.xls.
---------------------------------------------------------------------------
    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\
---------------------------------------------------------------------------
    \6\ http://www.eia.doe.gov/pub/international/iealf/tableh1co2.xls.
    \7\ http://www.eia.doe.gov/oiaf/ieo/emissions.html.
    \8\ http://www.eia.doe.gov/oiaf/aeo/excel/aeotab_18.xls.
    \9\ http://www.eia.doe.gov/oiaf/aeo/excel/aeotab_18.xls.
---------------------------------------------------------------------------
    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 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 post-Cold 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, 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.
---------------------------------------------------------------------------
    \10\ International Energy Agency R&D Statistics, http://
www.iea.org/Textbase/stats/rd.asp.
---------------------------------------------------------------------------
    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 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 Asia-Pacific 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 low-carbon 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.

    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 syn-gas, 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.
    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 state-level regulations, policies and 
programs, that require all new coal-based 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.
    [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 gasification-based 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)


    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)


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.

   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), 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 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, conventional 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 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 non-leachable, 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.
    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. Gasification 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 
oxy-combustion, 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.
    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?
    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 application 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.
    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'' coal-
based 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 high-
temperature 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 full-scale 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 ton-per-day prototype unit.
    High-Temperature Gas Cleanup--Removing sulfur and other impurities 
from coal-derived 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 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 coal-feed 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 co-feeding 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.
    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 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 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 near-
zero 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, near-
zero 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 
        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 cost-effective 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 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 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 large-scale 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.
    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 two-thirds 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.
    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 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 remaining 
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 gasification-based 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 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.
    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 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.
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 gas-fired 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.
    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 carbon 
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 
demonstrations 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 electricity-sector 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.
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 low-moisture 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 clear-cut 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.
---------------------------------------------------------------------------
    \1\ Feasibility Study for an Integrated Gasification Combined Cycle 
Facility at a Texas Site, EPRI report 1014510, October 2006.
---------------------------------------------------------------------------
    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, commercial-scale 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 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 coal-based 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 larger-scale tests, to multiple full-scale 
demonstrations, and finally to deployment in full-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 
full-scale 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 ``learning-by-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.
---------------------------------------------------------------------------
    \2\ IEA Greenhouse Gas R&D Programme (IEA GHG), ``Estimating Future 
Trends in the Cost of CO2 Capture Technologies,'' 2006/5, 
January 2006.


    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 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.
    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                                     38-41% HHV      39-43% HHV      42-46% HHV      44-49% HHV
(Without CO2 Capture)
----------------------------------------------------------------------------------------------------------------
PC & IGCC Systems                                     31-32% HHV      31-35% HHV      33-39% HHV      39-46% HHV
(With CO2 Capture *)
----------------------------------------------------------------------------------------------------------------
* 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.


    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 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 multi-contaminant 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 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

        
        
    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 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.


    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 high-temperature 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.








    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 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 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.
---------------------------------------------------------------------------
    \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.
---------------------------------------------------------------------------
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 post-combustion 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 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 scale-up 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-electricity 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 post-combustion 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 ammonia-based 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 re-used), membranes, and biological systems. 
Funding comes from a variety of sources, primarily DOE or internal 
funds, but the funding is neither sufficient or well-enough 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.
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 non-power)--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\
---------------------------------------------------------------------------
    \4\ http://www.co2captureandstorage.info/
project_specific.php?project_id=26.
---------------------------------------------------------------------------
    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 Regional 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
----------------------------------------------------------------------------------------------------------------
                                                                              Anticipated amount injected by:
              Project                CO2 Source    Country       Start    --------------------------------------
                                                                               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                                        CoalAustralia          N/A            0            0          N/A
SaskPower                                     Coal         Canada    N/A            0            0          N/A
Ketzin/CO2                                 N/A      Germany         2007            0        50 KT        50 KT
STORE
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 long-term 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.


    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:
---------------------------------------------------------------------------
    \5\ http://web.mit.edu/coal/The Future of Coal.pdf.
    \6\ EPRI, Overview of Geological Storage of CO2, Report 
ID 1012798.

---------------------------------------------------------------------------
   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.


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 coal-derived 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.
---------------------------------------------------------------------------
    \7\ http://www.iogcc.state.ok.us/PDFS/
CarbonCaptureandStorageReportandSummary.pdf.
---------------------------------------------------------------------------
    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.
---------------------------------------------------------------------------
    \8\ http://www.epa.gov/safewater/uic/pdfs/
guide_uic_carbonsequestration_final-03-07.pdf.
---------------------------------------------------------------------------
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 report estimates the 
funding need at up to $800-$850 million per year, which approaches 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          .........  .........  .........  80%        80%
 Gasification
Combined Cycle      50%        50%        40%
 (IGCC),
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 
commercial-scale, 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?
    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 
coal-powered 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 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 
Proposals, 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 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 
demonstrations, operating on different coals, including both 
western 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 
dual-track 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 2\1/2\ times or 1\1/2\ 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?
    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.
    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?
    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.
    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 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 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.]
    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.]
                            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 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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