[Senate Hearing 110-120]
[From the U.S. Government Publishing Office]


                                                        S. Hrg. 110-120

                   COAL GASIFICATION: OPPORTUNITIES 
                             AND CHALLENGES

=======================================================================

                                HEARING

                               before the

                              COMMITTEE ON
                      ENERGY AND NATURAL RESOURCES
                          UNITED STATES SENATE

                       ONE HUNDRED TENTH CONGRESS

                             FIRST SESSION

                                   TO

ADDRESS OPPORTUNITIES AND CHALLENGES ASSOCIATED WITH COAL GASIFICATION, 
         INCLUDING COAL-TO-LIQUIDS AND INDUSTRIAL GASIFICATION

                               __________

                              MAY 24, 2007


                       Printed for the use of the
               Committee on Energy and Natural Resources


                              -------

                     U.S. GOVERNMENT PRINTING OFFICE

37-273 PDF                 WASHINGTON DC:  2007
---------------------------------------------------------------------
For sale by the Superintendent of Documents, U.S. Government Printing
Office  Internet: bookstore.gpo.gov Phone: toll free (866)512-1800
DC area (202)512-1800  Fax: (202) 512-2250 Mail Stop SSOP, 
Washington, DC 20402-0001



































               COMMITTEE ON ENERGY AND NATURAL RESOURCES

                  JEFF BINGAMAN, New Mexico, Chairman

DANIEL K. AKAKA, Hawaii              PETE V. DOMENICI, New Mexico
BYRON L. DORGAN, North Dakota        LARRY E. CRAIG, Idaho
RON WYDEN, Oregon                    CRAIG THOMAS, Wyoming
TIM JOHNSON, South Dakota            LISA MURKOWSKI, Alaska
MARY L. LANDRIEU, Louisiana          RICHARD BURR, North Carolina
MARIA CANTWELL, Washington           JIM DeMINT, South Carolina
KEN SALAZAR, Colorado                BOB CORKER, Tennessee
ROBERT MENENDEZ, New Jersey          JEFF SESSIONS, Alabama
BLANCHE L. LINCOLN, Arkansas         GORDON H. SMITH, Oregon
BERNARD SANDERS, Vermont             JIM BUNNING, Kentucky
JON TESTER, Montana                  MEL MARTINEZ, Florida

                    Robert M. Simon, Staff Director
                      Sam E. Fowler, Chief Counsel
              Frank Macchiarola, Republican Staff Director
             Judith K. Pensabene, Republican Chief Counsel





















                            C O N T E N T S

                              ----------                              

                               STATEMENTS

                                                                   Page

Bartis, James, Senior Policy Researcher, Rand Corporation, 
  Arlington, VA..................................................    23
Bingaman, Hon. Jeff, U.S. Senator from New Mexico................     1
Bunning, Hon. Jim, U.S. Senator from Kentucky....................     6
Denton, David, Director, Business Development, Eastman 
  Gasification Services Company, Kingsport, TN...................    31
Domenici, Hon. Pete V., U.S. Senator from New Mexico.............     3
Dorgan, Hon. Byron L., U.S. Senator from North Dakota............     4
Fulkerson, William, Senior Fellow, Institute for a Secure and 
  Sustainable Environment, University of Tennessee, Knoxville, TN    20
Herzog, Antonia, Staff Scientist, Climate Center, Natural 
  Resources Defense Council......................................     7
Ratafia-Brown, Jay, Senior Engineer and Supervisor, SAIC--Energy 
  Solutions Group, McLean, VA....................................    37
Salazar, Hon. Ken, U.S. Senator from Colorado....................     2

                                APPENDIX

Responses to additional questions................................    65





























 
                   COAL GASIFICATION: OPPORTUNITIES 
                             AND CHALLENGES

                              ----------                              


                         THURSDAY, MAY 24, 2007

                                       U.S. Senate,
                 Committee on Energy and Natural Resources,
                                                    Washington, DC.
    The committee met, pursuant to notice, at 9:35 a.m., in 
room SD-366, Dirksen Senate Office Building, Hon. Jeff 
Bingaman, chairman, presiding.

OPENING STATEMENT OF HON. JEFF BINGAMAN, U.S. SENATOR FROM NEW 
                             MEXICO

    The Chairman. Why don't we go ahead and get started?
    Thank you all for coming today. We're here to talk about 
coal gasification technology and how it can be used to meet our 
needs, both for energy security and reducing our contribution 
to global warming. Although the fundamental technology we're 
talking about today has been around for many decades, 
relatively recent developments in the technology point to a 
pathway that may allow us to use the abundant coal reserves 
that we have in a way that's responsible, for future 
generations. Our testimony today will help develop the policies 
that will guide that development in the right direction.
    Let me first indicate that this hearing will not be the 
last that we have on this subject, or the last hearing or 
workshop that we have on this subject. We will be holding a 
longer, more in-depth hearing or workshop on coal gasification, 
including coal-to-liquids, sometime in the next month or so. 
Senators Tester, Corker, Dorgan, Salazar, and Conrad, have all 
requested that we do so. I believe Senator Bunning has joined 
in that. Coal-to-liquids, in particular, has received great 
attention lately, due to the strong advocacy of various people 
on this committee, and also, Montana's Governor, Brian 
Schweitzer. I believe that we have much more to explore in that 
area, and in the related areas of industrial use of coal. So, I 
hope that today's hearing will be a good first step in 
assessing the future uses of clean coal technologies.
    We're entering a challenging time for energy in the United 
States. While our fuel prices are going up, we're becoming 
increasingly reliant on unstable, or unsavory, regimes for that 
fuel. We're facing an increasingly urgent need to begin 
addressing the real problems of global warming. I think we've 
reached a point of consensus around this place on those issues, 
and that's a positive development.
    As the stabilization wedges that were developed at 
Princeton, and are going to be referenced by at least some of 
our witnesses today, make clear, we need to make advances on 
many fronts at the same time if we're to deal with the issue of 
greenhouse gas emissions. No one technology or policy will 
suffice. It's very difficult to be sure which technology is 
going to be the most important for the future.
    The investments that we're going to be making in coming 
years are significant. I think we're well advised to be careful 
to make sure we don't make our challenges greater in other 
areas in trying to address our fuel needs.
    I don't think anyone here would seriously dispute that coal 
is an important part of our fuel mix for the foreseeable 
future. Our domestic reserves are abundant. The price spread 
between coal and other fossil fuels is likely to make coal a 
very attractive option for a long time.
    However, the capital associated with coal facilities, and 
particularly coal gasification facilities, is very high, often 
in the range of $3 or $4 billion, or even more. Their expected 
useful life is substantially more than 20 years. As a result, 
if we make a mistake and encourage the development of plants 
that we later find to be incompatible with our need to reduce 
greenhouse gas emissions, this could prove to be a costly 
mistake. For that reason, it makes sense for us to be careful 
to structure incentives so that we don't lose sight of where we 
need to be in the years ahead.
    I believe we need to try to get a greenhouse gas emissions 
framework in place as soon as possible. But, if that does not 
happen this year, I think most would agree that it is going to 
happen sometime in the relatively near future. The price 
signals are not in place today to force deployment of the 
cleanest technologies that we have available. That does not 
mean commercial development and demonstration of those 
technologies should have to wait.
    The best way to avoid economic shocks down the road is to 
lay the foundations today for the clean technologies that we 
will be deploying tomorrow throughout forward-looking, 
technology-forcing incentives.
    So, we have some very good witnesses today. I look forward 
to hearing from them. But, before introducing them, let me call 
on Senator Domenici for any comments he has.
    [The prepared statement of Sentor Salazar follows:]

   Prepared Statement of Hon. Ken Salazar, U.S. Senator From Colorado

    I want to thank Chairman Bingaman and Ranking Member 
Domenici for holding today's hearing on coal gasification, and 
efforts to convert coal to liquid fuels. During the Energy and 
Natural Resources Committee mark-up of the Energy Savings Act 
of 2007, we asked Chairman Bingaman and Ranking Member Domenici 
to hold a hearing on issues related to converting coal to 
liquid fuels. I appreciate the efforts of Chairman Bingaman, 
Ranking Member Domenici, and the committee staff that went into 
putting this hearing together so quickly.
    My home state of Colorado is endowed with many natural 
resources, including vast coal resources. In Colorado, 71% of 
the electricity we produce is generated with coal. Colorado 
consumed 18.9 million tons of coal in 2004, generating 37.5 
million megawatts of electricity. Most of this coal comes from 
Colorado, but some of it is from Wyoming.
    Coal is our most abundant domestic energy source. It 
provides more than 50% of our nation's electricity needs, and 
America has enough coal to last more than 200 years. 
Unfortunately, CO2 pollution from coal combustion is 
a main cause of global warming, which threatens my state's 
water resources, our economy, and our quality of life.
    Fortunately, there seems to be more than one way to 
reconcile coal use with protecting our climate, through new 
low-carbon technologies such as Integrated Gasification 
Combined Cycle (IGCC), oxy-coal combustion, coal gasification 
and ultra-supercritical generation. In addition, advancements 
in capturing carbon and safely sequestering it underground will 
allow our country to use coal, and at the same time reduce 
CO2 emissions. I am proud of the work this Committee 
did in the Energy Savings Act of 2007 to promote research, 
development and deployment of carbon capture and sequestration 
technologies, and to do an assessment of our nation's carbon 
storage capacity. What we learn from the national assessment 
may be valuable in determining optimal locations to place coal-
to-liquid plants in order for them to be near areas where the 
CO2 emissions can be safely sequestered.
    Advances in technology indicate that a coal-to-liquid plant 
using combined cycle technology, carbon capture and storage, 
and biomass as part of the fuel source can result in far lower 
greenhouse gas emissions. It is my understanding that some 
coal-to-liquid processes can use up to 30% biomass in the 
feedstock, which reduces the CO2 emissions from the 
process. The use of a renewable fuel like biomass in these 
plants presents a great opportunity to allow for an expanded 
use of coal without adding to global warming.
    Thank you Chairman Bingaman and Ranking Member Domenici for 
holding today's hearing so that we can learn more about how our 
country's greatest fossil fuel resource can be used to expand 
the production of domestic fuels.

   STATEMENT OF HON. PETE V. DOMENICI, U.S. SENATOR FROM NEW 
                             MEXICO

    Senator Domenici. Thank you very much, Mr. Chairman.
    I apologize for being a couple of minutes late, but it was 
impossible to get out of a traffic jam and get here any sooner. 
But I want to thank you, Senator, for holding this hearing.
    This hearing is not new to the committee. We've had several 
hearings and conferences on this issue since 2005. All of our 
sources of energy are going to be needed to help meet our 
Nation's energy needs, and strengthen our energy security. We 
will need wind, solar, geothermal, and all types of biomass. We 
will need nuclear energy, and, yes, we will need America's most 
abundant source of energy: coal. I have said, on numerous 
occasions, that the Nation will be using greater amounts of 
coal to meet our future energy demands. Today, coal-fired power 
plants account for 50 percent of electricity generation in the 
United States. EIA estimated that by 2030 this percentage will 
be 57 percent, up by a full 7 points. Today, we look at the 
usefulness of coal as a source of transportation fuel. I have 
many questions regarding the environmental issues surrounding 
this; however, I hope people will look at coal-to-liquids and 
ask, ``What are the challenges we must face?'' instead of 
asking how these challenges can be used to scare people. This 
issue deserves a full and fair debate, and we must consider our 
Nation's energy security.
    The rest of the world is competing against us for every 
drop of available oil and natural gas, and that competition 
will become more intense, not less. These nations--often with 
massive State-owned entities--will be competing against us to 
find new energy sources and intellectual resources to find, 
develop, and implement these new technologies. We must lead in 
developing clean coal technology, renewable technologies, and 
carbon sequestration technologies. The decision that this 
Congress will be making this year will set the American energy 
course for a number of generations to come.
    Coal is a source that we have an abundance of, and if we 
develop it wisely and lead the march to new clean coal, we will 
be, without any question, leading the parade of technologies to 
coal technology. It will give us economic potential to compete 
with the world's emerging economies.
    Here is what we know about coal-to-liquids: other 
countries, like South Africa, have been converting coal into 
transportation fuels through the Fischer-Tropsch process full-
time for some time. This is not a new technology. It has been 
around since prior to the second World War. A number of these 
processes to convert coal to transportation fuel have been 
invented and are being tested and implemented in various parts 
of the world, including China. Currently, China is constructing 
an 800,000-barrel-per-day coal-to-liquid facility, and the 
Chinese government proposes to build as much as 1 million 
barrels of daily coal-to-liquid capacity by 2020. Though there 
are many challenges to this, we should try to meet them, not 
run away from them. The National Energy Technology Laboratory 
recently released a report that indicates that the Fischer-
Tropsch's liquids facility, with carbon dioxide captured, is 
both technically and economically feasible. Many agree that 
technologies to remove carbon dioxide, and then sequester that 
carbon dioxide, exist, but large-scale tests of carbon dioxide 
sequestration must be completed.
    Some of our witnesses today will discuss ways to integrate 
biomass and coal-to-liquid technologies that would be nearly 
carbon-neutral.
    The United States Air Force is currently working with the 
National Energy Technology Laboratory and others to develop a 
domestically produced coal-based aviation fuel to supply all of 
the Air Force's aviation fuel needs. It would be cleaner 
burning, and it would also be domestically secure.
    I look forward to hearing from our witnesses today, and I'm 
excited by those who suggest that we can integrate coal-to-
liquid, gasification, and biomass, and produce transportation 
fuels in an environmentally safe manner.
    With that, I will close, and I look forward to the 
testimony today.
    Thank you very much, Mr. Chairman.
    The Chairman. Thank you very much.
    Senator Dorgan indicated he'd like to make a short 
statement, and then, if any of the other members would, we'll 
do that before we introduce the witnesses.
    Senator Dorgan.

  STATEMENT OF HON. BYRON L. DORGAN, U.S. SENATOR FROM NORTH 
                             DAKOTA

    Senator Dorgan. Mr. Chairman, not so much a statement as a 
comment: I am told I'm going to be called to offer an amendment 
on the floor on the temporary worker provision in a few short 
minutes, and it'll be an amendment to sunset that provision. 
So, before I get called away, I did want to make one point.
    Back in the 1970's, we began a movement toward coal 
gasification and a very big project. One was built on the 
prairies of North Dakota, called the Great Plains Coal 
Gasification Plant. Today, as we speak, it will be producing 
synthetic natural gas from lignite coal. It is a technological 
marvel. It exceeds everybody's expectation, produces not only 
synthetic gas, but also chemical byproducts. At the same time 
that we're doing that, we built a pipeline to transport the 
CO2 into Canada, and so the CO2 from this 
coal gasification plant--as we produce synthetic gas from 
lignite coal--the CO2 goes to Alberta, Canada, where 
it is invested into marginal oil wells to increase the 
productivity of oil recovery in Canada. It is, I think, the 
largest CO2 capture and beneficial use in the world.
    I just wanted to make that point, because the Fischer-
Tropsch process, and associated processes--much of this is not 
particularly new. We know we can do this. We have carbon-
capture issues, but we're showing, in North Dakota, with the 
largest example of that in the world, that we can do that, as 
well. So, I just wanted to make that point, in the event I get 
called away for my amendment, I wanted that to be understood, 
that this is working in our country, and we can do much, much 
more of it.
    [The prepared statement of Senator Dorgan follows:]
  Prepared Statement of Hon. Senator Byron Dorgan, U.S. Senator From 
                              North Dakota
   We all recognize that important energy legislation will be 
        coming to the floor of the Senate in early June. The Energy and 
        Natural Resources Committee has worked in a bipartisan way on a 
        number of bills and has proven to be very productive.
   During this time of high energy prices, U. S. dependence on 
        foreign sources of energy (particularly oil and natural gas), 
        our need for more renewable and alternative energy, and our 
        need to address climate change, all provide a clear signal that 
        more must be done.
   Coal is our most abundant, most secure, and lowest cost 
        American energy resource. Coal is a major base load resource 
        for power generation, and has to play a significant role in our 
        energy mix.
   We have the world's largest coal reserves, with more than 
        275 billion tons (250 years supply at current usage rates) and 
        we are the second largest consumer with over 1 billion tones 
        per year.
   Lignite produces about 8% of our nation's coal needs and is 
        vital to North Dakota since we have about 800 years worth of it 
        in North Dakota.
   We can and should find new and different ways to use coal.
   Opportunities for coal use in the production of hydrogen, 
        chemicals, fertilizer, and liquid fuels must be explored.
   I want to look at all of these options.
                   energy security and climate change
   We have come to a new intersection of energy policy and 
        climate change, and there is an opportunity.
   The debate over climate change science has ended, and many 
        of my colleagues have ideas and proposals to curb emissions.
   I believe there has been an attitude shift in the country 
        recognizing the potential impacts of climate change, and we 
        need to address climate change legislation in a thoughtful and 
        comprehensive manner.
   Curbing carbon emissions is a long-term issue, but we have 
        commercially ready technologies and opportunities such as 
        enhanced oil and gas recovery and recovery of coal bed methane.
   Experts estimate that the U.S. has over 40 years of carbon 
        dioxide storage capacity in our oil and gas fields, and the use 
        of the carbon dioxide in this way could more than double our 
        domestic oil and gas production and reserve base. This would 
        enhance our energy security.
   Another 35 years of carbon dioxide storage capacity can be 
        placed in un-mineable coal seams to possibly yield more natural 
        gas.
   The long-term solution is storage in deep saline formations 
        where we have the capacity to store hundreds of years of carbon 
        dioxide.
              industrial gasification and coal-to-liquids
   In order to unlock coal's potential, we need to do more than 
        offer half-baked ideas.
   I had several concerns with the original Thomas/Bunning 
        approach. It was very late in coming and had not been fully 
        vetted.
   We need to require carbon capture and storage for these 
        projects, but the Thomas approach only said that it was an 
        option.
   If we don't find ways to incorporate carbon capture and 
        storage then the total CO2 emissions from coal-to-
        liquids is almost twice that of petroleum today.
   The Thomas/Bunning approach had set a standard for coal 
        fuels at 21 billion gallons by 2022. But we still don't know 
        where that came from, what it is based on, or if that is an 
        achieveable figure.
   Our primary need is to focus on the right incentives to work 
        with public funds to develop a core number of these facilities 
        (like 4-5) with carbon capture so that they become viable to 
        investors.
   There is a pathway forward. I want to work with others on 
        the Energy Committee to find a way to make these happen.
   I look forward to the testimony and discussion with our 
        panel of witnesses.

    Senator Bunning. Just very short.
    The Chairman. Yes. Senator Bunning.

          STATEMENT OF HON. JIM BUNNING, U.S. SENATOR 
                         FROM KENTUCKY

    Senator Bunning. I really want to thank you, Mr. Chairman 
and Senator Domenici, for following up and having this hearing, 
and more hearings in relationship, so that we can put the 
record straight on the use of coal-to-liquids or coal 
gasification, carbon capture, carbon sequestration, the 
cleanness of which it burns--the fuel, I'm speaking about and 
the Air Force's direct interest in a domestic-based fuel. And I 
thank you, from the bottom of my heart, for holding this 
hearing.
    The Chairman. Great.
    Senator Tester, do you want to make any statement, or 
Senator Corker, either one?
    [No response.]
    The Chairman. OK, I'll introduce three of the witnesses, 
and then call on Senator Corker to introduce the other two that 
are from his State of Tennessee.
    The three that I'll introduce are: first, Dr. Antonia 
Herzog, who is the staff scientist with the Climate Center, the 
Natural Resources Defense Council, here in Washington. Thank 
you for being here. James Bartis is here, who is a senior 
policy researcher with RAND Corporation, here in Arlington, 
Virginia. Thank you for being here. Dr. Jay Ratafia-Brown is a 
senior engineer and supervisor with SAIC--Energy Solutions 
Group, in McLean, Virginia.
    Senator Corker, did you want to introduce the other two 
witnesses from your home State?
    Senator Corker. I'd be delighted to.
    I want to thank you, with the other Senators, for having 
these hearings. I know we've had numerous hearings in the past, 
along with the Finance Committee. I, too, want to thank you for 
following through and having these hearings again. I'm thrilled 
with the resources that we have in our own State as it relates 
to conquering these types of issues, and dealing with them, 
which makes me even more interested, obviously, in these types 
of technologies.
    I'm really pleased that today we have two great 
Tennesseans. Bill Fulkerson is a senior fellow at the Institute 
for a Secure and Sustainable Environment at the University of 
Tennessee, my alma mater. Before he joined the Institute, he 
was for 32 years at Oak Ridge Laboratory, a leader in helping 
us develop energy security here in our country. After that, he 
chaired the Department of Energy Laboratory R&D Working Group, 
and he's worked with an organization of R&D managers from 14 
laboratories, working on energy issues. He drove up from 
Tennessee. He's driving back after these hearings. We thank him 
for being here.
    David Denton is also from Tennessee. Eastman Chemical, 
since 1983, has been utilizing these technologies in a way that 
has led industry throughout America. In many ways, they are my 
inspiration, if you will, as it relates to this type of 
technology. David certainly is very highly involved in that, 
searching for new customers, if you will, in this particular 
technology. I welcome both of them here.
    Thank you very much.
    The Chairman. Thank you.
    Thank you all for being here. Why don't we just start with 
Dr. Herzog. Why don't you go ahead. If each of you will take 5 
to 6 minutes, and summarize the main points you'd like us to 
understand, we will include your full statement in the record.
    Go right ahead.

 STATEMENT OF ANTONIA HERZOG, STAFF SCIENTIST, CLIMATE CENTER, 
               NATURAL RESOURCES DEFENSE COUNCIL

    Ms.Herzog. Thank you very much. Thank you for this 
opportunity to testify today on the subject of coal 
gasification technology and its challenges and environmental 
impacts.
    I'm staff scientist in the Climate Center at NRDC, a 
national nonprofit organization of scientists, lawyers 
dedicated to protecting public health and the environment.
    I'd like to start by taking a broader perspective and 
considering the primary motivation for pursuing coal 
gasification technology. They are: its potential to reduce our 
dependence on foreign energy sources and reduce our 
CO2 emissions from conventional coal use.
    The first issue is tied to both national security concerns 
and the impact that several years of volatile and high natural-
gas and oil prices have had on our businesses and consumers. 
The second is the result of the urgent need to turn the tide on 
global warming.
    To the first motivation, coal has the advantages of being a 
cheap, abundant, and domestic resource, compared with oil and 
natural gas, and the process of coal gasification can produce 
substitutes for both of these.
    To the second, coal gasification allows for more efficient, 
cost-effective capture of CO2 from coal, which, if 
the CO2 is then permanently disposed of, can provide 
a lower carbon energy source than conventional coal use. Any 
use of coal gasification must meet both these needs adequately. 
Furthermore, I have to add that there are many disadvantages of 
coal, beyond its CO2 emissions, which simply cannot 
be ignored. From underground mining accidents and mountaintop-
removal mining to air emissions of acidic and toxic pollution, 
from coal combustion, to water pollution, from coal mining and 
combustion rates, the conventional coal fuel cycle is among the 
most environmentally destructive activities on Earth, and we 
simply cannot forget this. This is why we believe, at NRDC, we 
must first turn to energy efficiency and renewable energy. 
Energy efficiency remains the cheapest, cleanest, and fastest 
way to meet our environmental challenges and energy needs, 
while renewable energy is the fastest growing supply option 
today.
    Only then should we consider turning to methods that can 
potentially make coal more compatible with protecting health 
and the environment, and reducing our dependence on foreign 
energy sources. With the right standards and incentives, we can 
fundamentally transform the way coal is produced and used in 
the United States and around the world.
    Congress is now considering proposals to promote coal 
gasification technologies with the goals of replacing natural 
gas, oil, and conventional coal combustion for electricity. 
These proposals can not only be evaluated in terms of our 
energy security concerns, but must also be evaluated in the 
context of the compelling need to reduce global warming 
emissions steadily, significantly, starting now, and proceeding 
along a declining pathway throughout the century.
    My specialty is global warming, and so that's what I will 
focus on here. This is not in any way to downplay the other 
land, air, and water impacts, which are equally relevant and 
concerning to us.
    To avoid catastrophic global warming, the United States and 
other nations will need to deploy energy resources that result 
in much lower releases of CO2 than today's use of 
oil, gas, and coal. In short, we need to start now, and a slow 
start would mean a crash finish if we delayed starting soon. If 
we wait too long to deploy low-carbon technologies, then we 
would need to deploy them much faster than any conventional 
technology that has been deployed in recent decades. In 
addition, the effort would require prematurely retiring 
billions of dollars in capital stocks that will be built or 
bought online during the next 10 to 20 years, in the absence of 
appropriate CO2 limits.
    For the electricity sector, we believe that coal 
gasification technologies could play a significant role. More 
than 90 percent of the U.S. coal supply is used to generate 
electricity currently, and a little over half of the U.S. 
electricity supply is generated----
    Senator Domenici. Senator Bingaman--excuse me--could we ask 
the witness where her testimony is? Where is she testifying 
from?
    The Chairman. You're giving us a summary of the testimony 
you submitted to the committee, is that correct?
    Ms. Herzog. Yes. That's right.
    The Chairman. I think that--the testimony she gave us is 
right here in your book. It should be.
    Senator Domenici. Right.
    The Chairman. But she's just--yes--and she's just 
summarizing it for us.
    Senator Domenici. OK. I couldn't find a summary. The 
summary is not in here.
    Ms. Herzog. It isn't. I apologize.
    Senator Domenici. That's fine.
    Ms. Herzog. OK.
    Senator Domenici. I'll keep looking, and you'll be 
finished, and I'll still be looking.
    Ms. Herzog. Right, right.
    [Laughter.]
    Ms. Herzog. Well, I'll certainly supply my summary 
afterwards. I admit to having worked on it last night.
    Anyway, continuing, we do believe that you can use coal 
gasification to generate electricity, replacing conventional 
coal combustion, capturing 85 to 90 percent of the carbon, 
disposing of it permanently in geologic reservoirs, and this 
technology can be consistent with reducing our global warming 
emissions for the long term.
    Now moving on to liquid fuels. We do not believe this 
happens to be the case for liquid fuels produced using coal 
gasification currently. To assess the global warming 
implications of a large coal-to-liquids program, we need to 
examine the total life cycle or well-to-wheel emissions of 
these fuels. Coal contains about 20 percent more carbon per 
unit of energy, compared to petroleum. When the coal is 
converted to liquid fuels, two streams of CO2 are 
produced, one at the coal-to-liquids production plant, and the 
second from the vehicles when they burn the fuel. The 
unavoidable fact is that liquid fuel from coal contains the 
same amount of carbon as a gallon of gasoline or diesel made 
from crude. Thus, the potential for achieving significant 
CO2 emission reductions compared to crude is 
limited.
    Based on our analysis, that of EPA and Argonne National 
Lab, the total well-to-wheel CO2 emissions from 
liquid coal plants is twice as high as crude oil if the 
CO2 is released to the atmosphere. Obviously, 
introducing new fuel with twice the CO2 emissions is 
simply not compatible with addressing global warming. Even if 
the CO2 from the coal-to-liquids plants is captured, 
the well-to-wheels CO2 emissions would still be 
higher than today's crude oil system, and it is not clear how 
efficiently and effectively we can capture that CO2 
in the production process.
    Using coal to produce a significant amount of liquid for 
transportation fuels, we do not believe is compatible for our 
need to develop a low-CO2-emitting transportation 
sector.
    Let me just give a quick example of some of the problems. 
It's half of the alternative fuels----
    The Chairman. Could you summarize your----
    Ms. Herzog. Finish up?
    The Chairman. Yes, if you could----
    Ms. Herzog. OK.
    The Chairman [continuing]. That would be great, too.
    Ms. Herzog. I'm going to give you one example here.
    The Chairman. OK.
    Ms. Herzog. What is the best use of coal for the 
transportation sector? There are better paths, we believe, to 
take using coal. A ton of coal used in a power plant employing 
carbon capture and disposal to generate electricity for a plug-
in hybrid vehicle will displace more than twice as much oil as 
using the same coal to make liquid fuel in a plant that also 
uses carbon capture and disposal.
    Second, a hybrid vehicle running on liquid coal will emit 
ten times as much carbon dioxide per mile as that plug-in 
hybrid vehicle running on electricity made from coal using 
carbon capture and disposal.
    So, I'll leave that thought in mind as to which is the best 
path to take for coal gasification technology.
    [The prepared statement of Dr. Herzog follows:]
prepared statement of antonia herzog, staff scientist, climate center, 
                   natural resources defense council
    Thank you for the opportunity to testify today on the subject of 
coal gasification technology and the challenges it faces. My name is 
Antonia Herzog. I am a staff scientist in 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.
    One of the primary reasons that the electric power, chemical, and 
liquid fuels industries have become increasingly interested in coal 
gasification technology in the last several years is the volatility and 
high cost of both natural gas and oil. Coal has the advantages of being 
a cheap, abundant, and domestic resource compared with oil and natural 
gas. However, the disadvantages of conventional coal use cannot be 
ignored. From underground accidents and mountain top removal mining, to 
collisions 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.\1\
---------------------------------------------------------------------------
    \1\ ``Coal in a Changing Climate,'' NRDC position paper, February 
2007, http://www.nrdc.org/globalWarming/coal/coalclimate.pdf.
---------------------------------------------------------------------------
    But we can do better with both production and use of coal. And 
because the world is likely to continue to use significant amounts of 
coal for some time to come, we must do better. Energy efficiency 
remains the cheapest, cleanest, and fastest way to meet our energy and 
environmental challenges, while renewable energy is the fastest growing 
supply option. Increasing energy efficiency and expanding renewable 
energy supplies must continue to be the top priority, but we have the 
tools to make coal more compatible with protecting public health and 
the environment. With the right standards and incentives we can 
fundamentally transform the way coal is produced and used in the United 
States and around the world.
    In particular, coal use and climate protection do not need to be 
irreconcilable activities. While energy efficiency and greater use of 
renewable resources must remain core components of a comprehensive 
strategy to address global warming, development and use of technologies 
such as coal gasification in combination with carbon dioxide 
(CO2) capture and permanent disposal in geologic 
repositories under certain circumstances could enhance our ability to 
avoid a dangerous build-up of this heat-trapping gas in the atmosphere 
while creating a future for continued coal use.
    However, because of the long lifetime of carbon dioxide in the 
atmosphere and the slow turnover of large energy systems we must act 
without delay to start deploying these technologies as appropriate. 
Current government policies are inadequate to drive the private sector 
to invest in carbon capture and disposal systems in the timeframe we 
need them. To accelerate the development of these systems and to create 
the market conditions for their use, we need to focus government 
funding more sharply on the most promising technologies. More 
importantly, we need to adopt binding measures and standards that limit 
global warming emissions so that the private sector has a business 
rationale for prioritizing investment in this area.
    In addition, Congress should only allow new authorizations for 
expenditures or the commitment of federal fiscal resources, including 
an authorization for an appropriation, direct spending, tax measures, 
loan guarantees or other credit instruments, to support the research, 
development, demonstration or commercial deployment of an energy 
producing technology if that technology, when commercially deployed: 
(A) reduces greenhouse gas emissions, (B) reduces our dependence on 
oil; and (C) provides an economic benefit to the U.S. economy.
    Congress is now considering a variety of proposals to gasify coal 
as a replacement for natural gas and oil. These proposals need to be 
evaluated in the context of the compelling need to reduce global 
warming emissions steadily and significantly, starting now and 
proceeding constantly throughout this century. Furthermore, because 
today's coal mining and use also continues to impose a heavy toll on 
America's land, water, and air, damaging human health and the 
environment, it is also critical to examine the implications of a 
substantial coal gasification program on these values as well.
                  reducing natural gas and oil demand
    The nation's economy, our health and our quality of life depend on 
a reliable supply of affordable energy services. The most significant 
way in which we can achieve these national goals is to exploit the 
enormous scope to wring more services out of each unit of energy used 
and by aggressively promoting renewable resources. While coal 
gasification technology has been touted as the technology solution to 
supplement our natural gas and oil supply and reduce our dependence on 
natural gas and oil imports, the most effective way to lower natural 
gas and oil demand, and prices, is to waste less. America needs to 
first invest in energy efficiency and conservation to reduce demand, 
and to second promote renewable energy alternatives to supplement 
supply. Gasified coal may have a role to play, but in both the short-
term and over the next two decades, efficiency and renewables are the 
lead actors in an effective strategy to moderate natural gas and oil 
prices and balance our demand with reasonable expectations of supply.
Natural Gas
    Increasing energy efficiency is far-and-away the most cost-
effective way to reduce natural gas consumption and avoid emitting 
carbon dioxide and other damaging environmental impacts. Available 
technologies range from efficient lighting, including emerging L.E.D. 
lamps, to advanced selective membranes which reduce industrial process 
energy needs. Critical national and state policies include appliance 
efficiency standards, performance-based tax incentives, utility-
administered deployment programs, and innovative market transformation 
strategies that make more efficient designs standard industry practice.
    Conservation and efficiency measures such as these can have 
dramatic impacts in terms of price and savings.\2\ Moreover, all of 
these untapped gas efficiency ``resources'' will expand steadily, as a 
growing economy adds more opportunities to secure long-lived savings. 
California has aquarter century record of using comparable strategies 
to reduce both natural gas consumption and the accompanying utility 
bills. Recent studies commissioned by the Pacific Gas & Electric 
Company showed that by 2001 longstanding incentives and standards 
targeting natural gas equipment and use had cut statewide consumption 
for residential, commercial, and industrial purposes (excluding 
electric generation) by more than 20 percent.
---------------------------------------------------------------------------
    \2\ American Council for an Energy-Efficient Economy (ACEEE), Fall 
2004 Update on Natural Gas Markets, November 3, 2004. See also Consumer 
Federation of America, ``Responding to Turmoil in Natural Gas Markets: 
The Consumer Case for Aggressive Policies to Balance Supply and 
Demand,'' pp. 28, December 2004.
---------------------------------------------------------------------------
    Studies have consistently shown that reducing demand for natural 
gas by increasing renewable energy use will reduce natural gas prices. 
According to a report released by the U.S. Department of Energy's 
Lawrence Berkeley National Laboratory, ``studies generally show that 
each 1% reduction in national gas demand is likely to lead to a long-
term (effectively permanent) average reduction in wellhead gas prices 
of 0.8% to 2%. Reductions in wellhead prices will reduce wholesale and 
retail electricity rates and will also reduce residential, commercial, 
and industrial gas bills.''\3\
---------------------------------------------------------------------------
    \3\ U.S. Department of Energy, Lawrence Berkeley National 
Laboratory, Easing the Natural Gas Crisis: Reducing Natural Gas Prices 
Through Increased Deployment of Renewable Energy and Energy Efficiency, 
January, 2005, p. 13.
---------------------------------------------------------------------------
    Adoption of a national renewable energy standard (RES) can 
significantly reduce the demand for natural gas, alleviating potential 
shortages. The Energy Information Administration (EIA) has found that a 
national 10 percent renewable energy standard could reduce gas 
consumption by 1.4 trillion cubic feet per year in 2020 compared to 
business as usual, or roughly 5 percent of annual demand. Furthermore, 
there would be a $4.9 billion cumulative present value savings for 
industrial gas consumers, $1.8 billion to commercial customers, and 
$2.4 billion to residential customers.\4\ EIA also found that renewable 
energy can help reduce electricity bills. Lower natural gas prices for 
electricity generators and other consumers offset the slightly higher 
cost of renewable electricity technology.\5\
---------------------------------------------------------------------------
    \4\ EIA, Impacts of a 10-Percent Renewable Portfolio Standard, SR/
OIAF/2002-03, February 2002. EIA, Analysis of a 10-Percent Renewable 
Portfolio Standard, SR/OIAF/2003-01, May 2003.
    \5\ UCS, Renewable Energy Can Help Alleviate Natural Gas Crisis, 
June 2003, at 2.
---------------------------------------------------------------------------
    Implementing effective energy efficiency measures is the fastest 
and most cost effective approach to balancing natural gas demand and 
supply. Renewable energy provides a critical mid-term to long-term 
supplement. Analysis by the Union of Concerned Scientists found that a 
combined efficiency and renewable energy scenario could reduce gas use 
by 31 percent and natural gas prices by 27 percent compared to business 
as usual in 2020.\6\
---------------------------------------------------------------------------
    \6\ UCS, Clean Energy Blueprint: A Smarter National Energy Policy 
for Today and the Future, October 2001.
---------------------------------------------------------------------------
    In contrast to these strategies, pursuing coal gasification 
implementation strategies that address only natural gas supply 
concerns, while ignoring impacts of coal, is a recipe for huge and 
costly mistakes. Fortunately, we have in our tool box energy resource 
options that can reduce natural gas demand and global warming emissions 
as well as protecting America's land, water, and air.
Oil
    NRDC fully agrees that reducing oil dependence should be a national 
priority and that new policies and programs are needed to avert the 
mounting problems associated with today's dependence and the much 
greater dependence that lies ahead if we do not act. A critical issue 
is the path we pursue in reducing oil dependence: a ``green'' path that 
helps us address the urgent problem of global warming and our need to 
reduce the impacts of energy use on the environment and human health; 
or a ``brown'' path that would increase global warming emissions as 
well as other health and environmental damage. In deciding what role 
coal might play as a source of transportation fuel NRDC believes we 
must thoroughly assess whether it is possible to use coal to make 
liquid fuels without exacerbating the problems of global warming, 
conventional air pollution and impacts of coal production and 
transportation.
    If coal were to play a significant role in displacing oil, it is 
clear that the enterprise would be huge, so the health and 
environmental stakes are correspondingly huge. The coal company Peabody 
Energy is promoting a vision that would call for production of 2.6 
million barrels per day of synthetic transportation fuel from coal by 
2025, about 10% of forecasted oil demand in that year. According to 
Peabody, using coal to achieve that amount of crude oil displacement 
would require construction of 33 very large coal-to-liquids plants, 
each plant consuming 14.4 million tons of coal per year to produce 
80,000 barrels per day of liquid fuel. Each of these plants would cost 
$6.4 billion to build. Total additional coal production required for 
this program would be 475 million tons of coal annually--requiring an 
expansion of coal mining of 43% above today's leve1.\7\ This testimony 
does not attempt a thorough analysis of the impacts of a program of 
this scale. Rather, it will highlight the issues that should be 
addressed in a detailed assessment.
---------------------------------------------------------------------------
    \7\ Peabody's ``Eight-Point Plan'' calls for a total of 1.3 billion 
tons of additional coal production by 2025, proposing that coal be used 
to produce synthetic pipeline gas, additional coal-fired electricity, 
hydrogen, and fuel for ethanol plants. The entire program would more 
than double U.S. coal mining and consumption.
---------------------------------------------------------------------------
                     environmental impacts of coal
    Some call coal ``clean.'' It is not and likely never will be 
compared to other energy options. Nonetheless, it appears inevitable 
that the U.S. and other countries will continue to rely heavily on coal 
for many years. The good news is that with the right standards and 
incentives it is possible to chart a future for coal that is compatible 
with protecting public health, preserving special places, and avoiding 
dangerous global warming. It may not be possible to make coal clean, 
but by transforming the way coal is produced and used, it is possible 
to make coal significantly cleaner--and safer--than it is today.
Global Warming Pollution
    To avoid catastrophic global warming the U.S. and other nations 
will need to deploy energy resources that result in much lower releases 
of CO2 than today's use of oil, gas and coal. To keep global 
temperatures from rising to levels not seen since before the dawn of 
human civilization, the best expert opinion is that we need to get on a 
pathway now to allow us to cut global warming emissions by up to 80 
percent from today's levels over the decades ahead. The technologies we 
choose to meet our future energy needs must have the potential to 
perform at these improved emission levels.
    Most serious climate scientists now warn that there is a very short 
window of time for beginning serious emission reductions if we are to 
avoid truly dangerous greenhouse gas reductions without severe economic 
impact. Delay makes the job harder. The National Academy of Sciences 
recently stated: ``Failure to implement significant reductions in net 
greenhouse gases will make the job much harder in the future--both in 
terms of stabilizing their atmospheric abundances and in terms of 
experiencing more significant impacts.''\8\
---------------------------------------------------------------------------
    \8\ National Academy of Sciences, Understanding and Responding to 
Climate Change: Highlights of National Academies Reports, p.16 (October 
2005), http://dels.nas.edu/dels/rpt briefs/climate-change-final.pdf.
---------------------------------------------------------------------------
    In short, a slow start means a crash finish--the longer emissions 
growth continues, the steeper and more disruptive the cuts required 
later. To prevent dangerous global warming we need to stabilize 
atmospheric concentration at or below 450 ppm, which would keep total 
warming below 2 degrees Celsius (3.6 degrees Fahrenheit). If we start 
soon, we can stay on the 450 ppm path with an annual emission reduction 
rate that gradually ramps up, but if we delay a serious start by 10 
years or more and continue emission growth at or close to the business-
as-usual trajectory, the annual emission reduction rate required to 
stay on the 450 ppm pathway jumps many-fold\9\. Even if you do not 
accept today that the 450 ppm path will be needed consider this point. 
If we do not act to preserve our ability to get on this path we will 
foreclose the path not just for ourselves but for our children and 
their children. We are now going down a much riskier path and if we do 
not start reducing emissions soon neither we nor our children can turn 
back no matter how dangerous the path becomes.
---------------------------------------------------------------------------
    \9\ D. D. Doniger, A.V. Herzog, D. A. Lashof, ``An Ambitious, 
Centrist Approach to Global warming Legislation,'' Science, vol. 314, 
p. 764 (November, 2006).
---------------------------------------------------------------------------
    In the past, some analysts have argued that the delay/crash action 
scenario is actually the cheaper course, because in the future 
(somehow) we will have developed breakthrough technologies. But it 
should be apparent that the crash reductions scenario is implausible 
for two reasons. First, reducing emissions by a very high rate each 
year would require deploying advanced low-emission technologies at 
least several times faster than conventional technologies have been 
deployed over recent decades. Second, the effort would require 
prematurely retiring billions of dollars in capital stock--high-
emitting power plants, vehicles, etc.--that will be built or bought 
during the next 10-20 years under in the absence of appropriate 
CO2 emission limits. It also goes without saying that U.S. 
leadership is critical. Preserving the 450 ppm pathway requires other 
developed countries to reduce emissions at similar rates, and requires 
the key developing countries to dramatically reduce and ultimately 
reverse their emissions growth. U.S. leadership can make that happen 
faster.
    To assess the global warming implications of a large coal 
gasification program we need to carefully examine the total life-cycle 
emissions associated with the end product, whether electricity, 
synthetic gas, liquid fuels or chemicals, and to assess if the relevant 
industry sector will meet the emission reductions required to be 
consistent with what we need to achieve in the U.S.
            Electricity Sector
    More than 90 percent of the U.S. coal supply is used to generate 
electricity in some 600 coal-fired power plants scattered around the 
country, with most of the remainder is used for process heat in heavy 
industrial and in steel production. Coal is used for power production 
in all regionsof the country, with the Southeast, Midwest, and Mountain 
states most reliant on coal-fired power. Texas uses more coal than any 
other state, followed by Indiana, Illinois, Ohio, and Pennsylvania.\10\
---------------------------------------------------------------------------
    \10\ http://www.eia.doe.gov/cneaf/coal/page/acr/table26.html.
---------------------------------------------------------------------------
    About half of the U.S. electricity supply is generated using coal-
fired power plants. This share varies considerably from state to state, 
but even California, which uses very little coal to generate 
electricity within its borders, consumes a significant amount of 
electricity generated by coal in neighboring Arizona and Nevada, 
bringing coal's share of total electricity consumed in California to 20 
percent.\11\ National coal-fired capacity totals 330 billion watts 
(GW), with individual plants ranging in size from a few million watts 
(MW) to over 3000 MW. More than one-third of this capacity was built 
before 1970, and over 400 units built in the 1950s--with capacity 
equivalent to roughly 100 large modern plants (48 GW)--are still 
operating today.
---------------------------------------------------------------------------
    \11\ California Energy Commission, 2005. 2004 Net System Power 
Calculation (April.) Table 3: Gross System Power. http://
www.energy.ca.gov/2005publications/CEC-300-2005-004/CEC-300-2005-
004.PDF.
---------------------------------------------------------------------------
    The future of coal in the U.S. electric power sector is an 
uncertain one. The major cause of this uncertainty is the government's 
failure to define future requirements for limiting greenhouse gas 
emissions, especially carbon dioxide (CO2). Coal is the 
fossil fuel with the highest uncontrolled CO2 emission rate 
of any fuel and is responsible for 36 percent of U.S. carbon dioxide 
emissions. Furthermore, coal power plants are expensive, long-lived 
investments. Key decision makers understand that the problem of global 
warming will need to be addressed within the time needed to recoup 
investments in power projects now in the planning stage. Since the 
status quo is unstable and future requirements for coal plants and 
other emission sources are inevitable but unclear, there will be 
increasing hesitation to commit the large amounts of capital required 
for new coal projects.
    Electricity production is the largest source of global warming 
pollution in the U.S. today. In contrast to nitrogen and sulfur oxide 
emissions, which have declined significantly in recent years as a 
result of Clean Air Act standards, CO2 emissions from power 
plants have increased by 27 percent since 1990. Any solution to global 
warming must include large reductions from the electric sector. Energy 
efficiency and renewable energy are well-known low-carbon methods that 
are essential to any climate protection strategy. But technology exists 
to create a more sustainable path for continued coal use in the 
electricity sector as well. Coal gasification can be compatible with 
significantly reducing global warming emissions in the electric sector 
if it replaces conventional coal combustion technologies, directly 
produces electricity in an integrated manner, and most importantly 
captures and disposes of the carbon in geologic formations. IGCC 
technology without CO2 capture and disposal achieves only 
modest reductions in CO2 emissions compared to conventional 
coal plants.
    A coal integrated gasification combined cycle (IGCC) power plant 
with carbon capture and disposal can capture up to 90 percent of its 
emissions, thereby being part of the global warming solution. In 
addition to enabling lower-cost CO2 capture, gasification 
technology has very low emissions of most conventional pollutants and 
can achieve high levels of mercury control with low-cost carbon-bed 
systems. However, it still does not address the other environmental 
impacts from coal production and transportation.
    The electric power industry has been slow to take up gasification 
technology, but two commercial-scale units are operating in the U.S.--
in Indiana and Florida. The Florida unit, owned by TECO, is reported by 
the company to be the most reliable and economic unit on its system. 
Two coal-based power companies, AEP and Cinergy, have announced their 
intention to build coal gasification units. The first proposed coal 
gasification plant that will capture and dispose of its CO2 
was announced in February, 2006 by BP and Edison Mission Group. The 
plant will be built in Southern California and its CO2 
emissions will be pipelined to an oil field nearby and injected into 
the ground to recover domestic oil. BP's proposal shows the 
technologies are available now to cut global warming pollution and that 
integrated IGCC with CO2 capture and disposal are 
commercially feasible.
            Liquid Fuels
    To assess the global warming implications of a large coal-to-
liquids program we need to examine the total life-cycle or ``well-to-
wheel'' emissions of these new fuels. Coal is a carbon-intensive fuel, 
containing double the amount of carbon per unit of energy compared to 
natural gas and about 20% more than petroleum. When coal is converted 
to liquid fuels, two streams of CO2 are produced: one at the 
coal-to-liquids production plant and the second from the exhausts of 
the vehicles that burn the fuel. With the technology in hand today and 
on the horizon it is difficult to see how a large coal-to-liquids 
program can be compatible with the low-CO2-emitting 
transportation system we need to design to prevent global warming.
    Today, our system of refining crude oil to produce gasoline, 
diesel, jet fuel and other transportation fuels, results in a total 
``well-to-wheels'' emission rate of about 27.5 pounds of CO2 
per gallon of fuel. Based on available information about coal-to-
liquids plants being proposed, the total well to wheels CO2 
emissions from such plants would be about 49.5 pounds of CO2 
per gallon, nearly twice as high as using crude oil, if the 
CO2 from the coal-to-liquids plant is released to the 
atmosphere.\12\ Obviously, introducing a new fuel system with close to 
double the CO2 emissions of today's crude oil system would 
conflict with the need to reduce global warming emissions. If the 
CO2 from coal-to-liquids plants is captured, then well-to-
wheels CO2 emissions would be reduced but would still be 
higher than emissions from today's crude oil system.\13\
---------------------------------------------------------------------------
    \12\ Calculated well-to-wheel CO2 emissions for coal-
based ``Fischer-Tropsch'' are about 1.8 greater than producing and 
consuming gasoline or diesel fuel from crude oil. If the coal-to-
liquids plant makes electricity as well, the relative emissions from 
the liquid fuels depends on the amount of electricity produced and what 
is assumed about the emissions of from an alternative source of 
electricity.
    \13\ Capturing 90 percent of the emissions from coal-to-liquid 
plants reduces the emissions from the plant to levels close to those 
from petroleum production and refining while emissions from the vehicle 
are equivalent to those from a gasoline vehicle. With such 
CO2 capture, well to wheels emissions from coal-to-liquids 
fuels would be 8 percent higher than for petroleum.
---------------------------------------------------------------------------
    This comparison indicates that using coal to produce a significant 
amount of liquids for transportation fuel would not be compatible with 
the need to develop a low-CO2 emitting transportation sector 
unless technologies are developed to significantly reduce emissions 
from the overall process. But here one confronts the unavoidable fact 
that the liquid fuel from coal contains the same amount of carbon as is 
in gasoline or diesel made from crude. Thus, the potential for 
achieving significant CO2 emission reductions compared to 
crude is inherently limited. This means that using a significant amount 
of coal to make liquid fuel for transportation needs would make the 
task of achieving any given level of global warming emission reduction 
much more difficult. Proceeding with coal-to-liquids plants now could 
leave those investments stranded or impose unnecessarily high abatement 
costs on the economy if the plants continue to operate.
    NRDC has examined the greenhouse gas emissions from a wide variety 
of feedstock and conversion process combinations using the Argonne 
GREET model (see figure 1* and Appendix 1). EPA conducted a similar 
analysis for a factsheet released in conjunction with its final rule 
for implementing the Renewable Fuels Standard enacted in EPACT 
2005.\14\ EPA's results are shown in Figure 2 and are very similar to 
ours (note that EPA displays results relative to conventional diesel 
gasoline, which is set to zero on their chart). Most recently Argonne 
National Laboratory scientist released a new analysis using their GREET 
model to assess the life-cycle greenhouse gas emissions of Fischer-
Tropsch diesel products from natural gas, coal and biomass (see figure 
3).\15\ Again their results are similar to ours. They find that liquid 
coal without carbon capture and disposal can emit from 2.2 to 2.5 times 
more greenhouse gases than the equivalent gallon of petroleum-based 
diesel fuel. And even with carbon capture and disposal the life-cycle 
emissions are still 1.19-1.25 times higher.
---------------------------------------------------------------------------
    * Figures 1-5 have been retained in committee files.
    \14\  http://www.epa.gov/otaq/renewablefuels/420f07035.htm
    \15\ M. Wang, M. Wu, H. Huo, ``Life-cycle energy and greenhouse gas 
results of Fischer-Tropsch diesel produced from natural gas, coal, and 
biomass,'' Center for Transportation Research, Argonne National 
laboratory, presented at 2007 SAE Government/Industry meeting, 
Washington, DC, May 2007.
---------------------------------------------------------------------------
    From these charts we can clearly see that there are much more 
environmentally friendly methods for producing transportation fuels. 
Biofuels are an obvious alternative, which has gotten a lot of 
attention recently, and about which NRDC recently testified before the 
committee.\16\ Another alternative transportation fuel that is worthy 
of note is electricity used in plug-in hybrid electric vehicles. If 
coal is to be used to replace gasoline, generating electricity for use 
in plug-in hybrid vehicles (PHEVs) can be far more efficient and 
cleaner than making liquid fuels. In fact, a ton of coal used to 
generate electricity used in a PHEV will displace more than twice as 
much oil as using the same coal to make liquid fuels, even using 
optimistic assumptions about the conversion efficiency of liquid coal 
plants.\17\ The difference in CO2 emissions is even more 
dramatic. Liquid coal produced with CCS and used in a hybrid vehicle 
would still result in lifecycle greenhouse gas emissions of 
approximately 330 grams/mile, or ten times as much as the 33 grams/mile 
that could be achieve by a PHEV operating on electricity generated in a 
coal-fired power plant equipped with CCS.\18\ GM has recently announced 
plans to commercialize plug-in hybrid electric vehicles.
---------------------------------------------------------------------------
    \16\ Daniel Lashof, Testimony on S.987, the Biofuels for Energy 
Security and Transportation Act of 2007 before the Senate Energy and 
Natural Resources Committee, April 12, 2007. http://docs.nrdc.org/
globalwarming/glo_07041201A.pdf.
    \17\ Assumes production of 84 gallons of liquid fuel per ton of 
coal, based on the National Coal Council report. Vehicle efficiency is 
assumed to be 37.1 miles/gallon on liquid fuel and 3.14 miles/kWh on 
electricity.
    \18\ Assumes lifecycle greenhouse gas emission from liquid coal of 
27.3 lbs/gallon and lifecycle greenhouse gas emissions from an IGCC 
power plant with CCS of 106 grams/kWh, based on R. Williams et al., 
paper presented to GHGT-8 Conference, June 2006.
---------------------------------------------------------------------------
    Simply put, liquid coal is highly unlikely to be compatible with 
long-term climate protection. A recent analysis by Jim Dooley of 
Battelle National Laboratory shows that liquid coal is not part of an 
energy system that is consistent with stabilizing greenhouse gas 
concentrations at or below 450ppm. (see figure 4).\19\ Furthermore, 
using high-carbon fuels for transportation means we would have to do 
that much more in improving other areas of transportation, such as 
increased vehicle efficiency and reduced vehicle miles traveled. The 
Administration's alternative fuels proposal highlights this fact. If 
half of the alternative fuels mandate proposed by the administration 
were satisfied with coal-derived liquid fuels then CO2 
emissions would be 175 million tons higher in 2017 than the 
administration's target. To offset this increase through automobile 
fuel efficiency standards would have to increase by 8.6 percent per 
year, rather than the 4 percent per year as suggested by the 
administration.
---------------------------------------------------------------------------
    \19\ Jim Dooley, Robert Dahowski, Marshall Wise, Casie Davidson 
``Coal-to-Liquids and Advanced Low-Emissions Coal-fired Electricity 
Generation,'' presentation at NETL conference, May 9, 2007, PNWD-SA-
7804.
---------------------------------------------------------------------------
    With liquid coal proposals proliferating in Congress it is critical 
to evaluate the environmental ramifications of these proposals. In 
particular, recently offered before the Senate Energy and Natural 
Resources committee during their May 2, 2007 energy legislation markup 
was an amendment co-authored by Senators Thomas and Bunning mandating 
21 billion gallons of liquid coal synfuels per year by 2022.
    Producing 21 billion gallons of liquid coal synfuels per year would 
require building up to 40 new medium sized (35,000 barrels/day) liquid 
coal plants. This in turn would:

   Increase global warming pollution by almost 600 million 
        metric tons CO2 per year. Even with carbon capture 
        and disposal CO2 emissions are still higher than 
        conventional fuels, and while cofiring with biomass with carbon 
        capture and disposal can produce diesel fuels with life-cycle 
        emissions below conventional diesel fuels, this technology is 
        still in the development stages.
   Create water shortages in the West by requiring an 
        additional 100 billion gallons of water usage per year, the 
        equivalent of 375 empire state buildings of water per year. One 
        gallon of liquid coal requires five gallons of water to 
        produce. It is expected that many of the forty new coal plants 
        required to produce this fuel would be built in the West where 
        water shortages are already a severe problem.
   Scar the landscape by requiring 250 million additional tons 
        of coal, a 23% increase in coal mining compared to 2006 coal 
        mining production. This increase would have severe impacts on 
        our land, air and water.

    While Senators Thomas and Bunning have acknowledged the importance 
of global warming pollution by requiring that emissions from liquid 
coal synfuels not exceed those from conventional gasoline we need to be 
doing much better than that to meet the emission reductions that will 
be necessary from the transportation sector (see figure 4).
            Synthetic Gas
    Another area that has received interest is coal gasification to 
produce synthetic natural gas as a direct method of supplementing our 
natural gas supply from domestic resources. However, without 
CO2 capture and disposal this process results in more than 
twice as much CO2 per 1000 cubic feet of natural gas 
consumed compared to conventional resources.\20\ From a global warming 
perspective this is unacceptable. With capture and disposal the 
CO2 emissions can be substantially reduced, but still remain 
12 percent higher than natural gas.
---------------------------------------------------------------------------
    \20\ The National Coal Council, ``Coal: America's Energy Future,'' 
March 22, 2006. This report actually assumes a less efficient coal to 
synthetic gas conversion process of 50% leading to three times as much 
CO2 per 1000 cubic feet of natural gas consumed compared to 
conventional resources.
---------------------------------------------------------------------------
    In Beulah, North Dakota the Basin Electric owned Dakota 
Gasification Company's Great Plains Synfuels Plant is a 900MW facility 
which gasifies coal to produce synthetic ``natural'' gas. It can 
produce 150 million cubic feet of synthetic gas per day and 11,000 tons 
of CO2 per day. However, it no longer releases all of its 
CO2 to the atmosphere, but captures most of it and pipes it 
200 miles to an oil field near Weyburn, Saskatchewan. There the 
CO2 is pumped underground into an aging oil field to recover 
more oil. EnCana, operator of this oil field, pays $2.5 million per 
month for the CO2. They expect to sequester 20 million tons 
of CO2 over the lifetime of this injection project.
    A potential use for coal-produced synthetic gas would be to burn it 
in a gas turbine at another site for electricity generation. This 
approach would result in substantially higher CO2 emissions 
than producing electricity in an integrated system at the coal 
gasification plant with CO2 capture at the site (i.e., in an 
IGCC plant with carbon capture and disposal). Coal produced synthetic 
natural gas could also be used directly for home heating. As a 
distributed source of emissions the CO2 would be prohibitive 
to capture with known technology.
    Before producing synthetic pipeline gas from coal a careful 
assessment of the full fuel cycle emissions against the baseline and 
alternatives and the emission reductions that are required from that 
sector must be carried out before decisions are made to invest in these 
systems.
            Chemical Products
    The chemical industry has also been looking carefully at coal 
gasification technology as a way to replace the natural gas feedstock 
used in chemical production. The motivator has been the escalating and 
volatile costs of natural gas in the last few years. A notable example 
in the U.S. of such a use is the Tennessee Eastman plant, which has 
been operating for more than 20 years using coal instead of natural gas 
to make chemicals and industrial feedstocks. If natural gas is replaced 
by coal gasification as a feedstock for the chemical industry, first 
and foremost CO2 capture and disposal must be an integral 
part of such plants. In this case, the net global warming emissions 
will change relatively little from this sector compared to the 
conventional natural gas based process. Steam reforming of natural gas, 
however, could also potentially capture its emissions too, resulting in 
even lower emissions. Therefore, before such a transformation occurs 
with coal as a feedstock, a careful analysis of the entire life cycle 
emissions needs to be carried out against the baseline and 
alternatives, along with an assessment of how future emissions 
reductions from this sector can be most effectively accomplished.
Conventional Air Pollution
    Dramatic reductions in power plant emissions of criteria 
pollutants, toxic compounds, and global warming emissions are essential 
if coal is to remain a viable energy resource for the 21st Century. 
Such reductions are achievable in integrated gasification combined 
cycle (IGCC) systems, which enable cost-effective advanced pollution 
controls that can yield extremely low criteria pollutant and mercury 
emission rates and facilitates carbon dioxide capture and geologic 
disposal. Gasifying coal at high pressure facilitates removal of 
pollutants that would otherwise be released into the air such that 
these pollutant emissions are well below those from conventional 
pulverized coal power plants with post combustion cleanup.
    Conventional air emissions from coal-to-liquids plants include 
sulfur oxides, nitrogen oxides, particulate matter, mercury and other 
hazardous metals and organics. While it appears that technologies exist 
to achieve high levels of control for all or most of these pollutants, 
the operating experience of coal-to-liquids plants in South Africa 
demonstrates that coal-to-liquids plants are not inherently ``clean.'' 
If such plants are to operate with minimum emissions of conventional 
pollutants, performance standards will need to be written--standards 
that do not exist today in the U.S. as far as we are aware.
    In addition, the various federal emission cap programs now in force 
would apply to few, if any, coal-to-liquids plants.\21\
---------------------------------------------------------------------------
    \21\ The sulfur and nitrogen caps in EPA's ``Clean Air Interstate 
Rule'' (``CAIR'') may cover emissions from coal-toliquids plants built 
in the eastern states covered by the rule but would not apply to plants 
built in the western states. Neither the national ``acid rain'' caps 
nor EPA's mercury rule would apply to coal-to-liquids plants.
---------------------------------------------------------------------------
    Thus, we cannot say today that coal-to-liquids plants will be 
required to meet stringent emission performance standards adequate to 
prevent either significant localized impacts or regional emissions 
impacts.
Mining, Processing and Transporting Coal
    The impacts of mining, processing, and transporting 1.1 billion 
tons of coal today on health, landscapes, and water are large. To 
understand the implications of continuing our current level of as well 
as expanding coal production, it is important to have a detailed 
understanding of the impacts from today's level of coal production. It 
is clear that we must find more effective ways to reduce the impacts of 
mining, processing and transporting coal before we follow a path that 
would result in even larger amounts of coal production and 
transportation.
    the path forward: an action plan to reduce u.s. global warming 
                               pollution
    The United Nations Framework Convention on Climate Change (UNFCCC) 
establishes the objective of preventing ``dangerous anthropogenic 
interference with the climate system.'' While a ``non-dangerous'' 
concentration level has not been defined under the UNFCCC and is not a 
purely scientific concept, the European Union has set a goal of 
avoiding an increase of more than 2 degrees Celsius from pre-industrial 
levels in order to avoid the most dangerous changes to climate. We 
believe this is a sound goal and U.S. emission reduction policies 
should have a similar objective.
    To prevent dangerous global warming while allowing for a reasonable 
transition in developing nations, the U.S. needs to start to cut global 
warming pollution as soon as possible and keep steadily reducing 
emissions over time. Specifically, U.S. emissions in 2020 should be at 
least 15-20% below current levels.\22\ By mid-century, U.S. emissions 
need to be reduced on the order of 80 percent. A variety of existing 
technologies can be deployed to achieve these goals--and, in addition, 
the right policies will spur investment and innovation to create new 
fuels and technologies. By solving this smartly, we can create jobs and 
improve our standard of living even as we tackle this dangerous 
problem.
---------------------------------------------------------------------------
    \22\ 15% below 2005 levels is equivalent to 1990 levels, and is 
also equivalent to approximately 35% below businessas-usual levels for 
2020. The Sander-Boxer Global Warming Pollution Reduction Act, S. 309, 
meets these emission reduction goals.
---------------------------------------------------------------------------
    A valuable framework in which to visualize a long-term emissions 
reductions pathway is through the ``wedges'' analysis pioneered by 
Professors Robert Socolow and Steve Pacala at Princeton University.\23\ 
NRDC has modified their study, which analyzed global emission reduction 
pathways, to consider potential U.S. emission reduction pathways.
---------------------------------------------------------------------------
    \23\ S. Pacala and R. Socolow, ``Stabilization Wedges: Solving the 
Climate Problem for the Next 50 Years with Current Technologies,'' 
Science, v. 305, p. 968 (2004).
---------------------------------------------------------------------------
    The structure of our analysis is a detailed extension of the 
Socolow-Pacala concept of emission reduction ``stabilization wedges'' 
decreases in emissions in measurable increments from a business as 
usual projection attributable to specific technologies. These wedge 
increments can then be summed up in various ways (as ``paths'') to the 
desired emission reduction total (See figure 5).
    NRDC used a spreadsheet model developed by Kuuskraa et al. to 
examine U.S. emissions scenarios out to 2050.\24\ This analysis 
segregates the wedges into four sectors: electricity, transportation, 
stationary end-use fuel combustion, and non-CO2 gases. This 
segregation helps to avoid double counting different measure so as to 
develop self-consistent scenarios for the U.S. energy system (for 
example, taking credit for reducing the demand of electricity from 
appliances while at the same time reducing emissions at power plants 
that supply the power).
---------------------------------------------------------------------------
    \24\ V. Kuuskraa, P. Dipietro, S. Klara, S. Forbes, ``Future U.S. 
Greenhouse Gas Emission Reduction Scenarios Consistent with Atmospheric 
Stabilization Concentrations,'' GHGT-7, .506 (2004).
---------------------------------------------------------------------------
    Their spreadsheet model is used here to construct an emissions 
scenario consistent with the U.S. carbon budget that meets an 80 
percent reduction below 1990 levels by 2050 using technologies that are 
likely to be available and affordable during that timeframe. In this 
scenario the largest reductions are obtained from energy efficiency 
improvements in electrical end uses, non-electric stationary end uses, 
and motor vehicles. Additional reductions come from renewable fuels and 
electricity and carbon capture and disposal at coal-fired power plants 
and other high-concentration industrial CO2 vents. The 
elements of this scenario are briefly outlined below.
    Electricity (first 3 wedges)--The U.S. gets just over half of its 
electricity from coal, about a fifth from nuclear power, and the 
balance mainly from natural gas and renewable energy sources. Natural 
gas is considered limited by supply and price constraints and 
hydroelectric power, the dominant renewable resource, is limited by the 
fact that the best available sites have already been dammed. In 
addition, the expansion of nuclear power continues to hit a variety of 
impediments. Therefore, for the electricity sector we assume:

   High levels of efficiency in end-use consumption and supply 
        production and distribution to meet growing energy needs, 
        thereby reducing the need to construct new baseload power 
        plants while expanding renewable energy sources.

    --40% of electricity (1600 Billion kWh) is generated from non-hydro 
            renewables: Wind, geothermal, solar thermal, PV, and 
            biomass (coproduced with biofuels).

   Building some coal plants with geologic carbon dioxide 
        disposal to replace existing coal-fired plants as they reach 
        retirement age.

    --16% of electricity (660 Billion kWh) is generated from coal with 
            carbon capture and geologic disposal.

   Nuclear would remain roughly the same proportion of 
        electricity that it does currently.

    Transportation (second 3 wedges)--Controlling emission from the 
burning of oil by the transportation sector requires a combination of 
reducing the number of miles people drive in their cars and other 
vehicles (Vehicle Miles Traveled or VMT), the efficiency of those 
vehicles in consuming as little fuel as possible, and the using low-
carbon fuels. The low-carbon fuels wedge assumes that there will be 
adequate environmental protections for the production of these fuels, 
while at the same time promoting maximum efficiency and electrification 
of the vehicle fleet.
    The scenario analyzed assumes:

   New vehicle fuel efficiency triples by 2050 and VMT is 
        reduced by 20% through smart growth policies.
    --New vehicle fuel efficiency is 3 times current level by 2050. On 
            road fleet average 55 mpg.

   Of the remaining fuel demand, 45% is satisfied with 
        electricity used in plug-in hybrid vehicles and 40% is 
        satisfied by biofuels, such that biofuels displace 36 billion 
        gallons of gasoline equivalent in 2050.\25\
---------------------------------------------------------------------------
    \25\ Assuming that about half of corn stover can be collected for 
energy use (200 million tons of waste material altogether), 22 million 
acres would have to be dedicated to energy crop production.

    Biological Sequestration and Other--There is a wedge that allows 
for a small amount of carbon dioxide to be absorbed by biological 
sources. While we do not support an over reliance on biological 
sequestration, because of a lack of reliability of such a mechanism, 
some biological sequestration is likely to occur. The other efficiency 
wedge incorporates efficiency improvements made in direct fuel demand 
by stationary sources and the other renewables wedge comes from 
renewables supplying 30 percent of other stationary source energy 
demand. Finally, there are other unidentified reduction opportunities, 
including international emissions trading.
    This analysis clearly shows how we can meet the required emission 
reduction targets through the deployment of a wide variety of low-
carbon technologies in multiple sectors of the economy over the next 
four decades. It is also clear that liquid coal is not compatible with 
this visions and would require the expansion of other low-carbon wedges 
to cover its emissions profile. Coal gasification for electricity 
production is consistent and integrated into the analysis. Further 
analysis is needed to assess whether the use of coal gasification for 
other products such as synthetic natural gas or chemicals would be at 
odds with the necessary reduction pathway.
                               conclusion
    The impacts that a large coal gasification program could have on 
global warming pollution, conventional air pollution and environmental 
damage resulting from the mining, processing and transportation of the 
coal are substantial. Before deciding whether to invest scores, perhaps 
hundreds of billions of dollars in deploying this technology, we must 
have a program to manage our global warming pollution and other coal 
related impacts. Otherwise we will not be developing and deploying an 
optimal energy system.
    One of the primary motivators for pushing coal gasification 
technologies has been to reduce natural gas prices. Fortunately, the 
U.S. can have a robust and effective program to reduce natural gas 
demand, and therefore prices, without rushing to embrace coal 
gasification technologies. A combination of efficiency and renewables 
can reduce our natural gas demand more quickly and more cleanly.
    The other major motivator for the push to use coal gasification is 
to produce liquid fuels to reduce our oil dependence. The U.S. can have 
a robust and effective program to reduce oil dependence without rushing 
into an embrace of liquid coal technologies. A combination of more 
efficient cars, trucks and planes, biofuels, and ``smart growth'' 
transportation options outlined above and in the report ``Securing 
America,'' produced by NRDC and the Institute for the Analysis of 
Global Security, which shows how to cut oil dependence by more than 3 
million barrels a day in 10 years, and achieve cuts of more than 11 
million barrels a day by 2025.
    To reduce our dependence on natural gas and oil we should follow a 
simple rule: start with the measures that will produce the quickest, 
cleanest and least expensive reductions in natural gas and oil use; 
measures that will put us on track to achieve the reductions in global 
warming emissions we need to protect the climate. If we are thoughtful 
about the actions we take, our country can pursue an energy path that 
enhances our security, our economy, and our environment.
    With current coal and oil consumption trends, we are headed for a 
doubling of CO2 concentrations by mid-century if we don't 
redirect energy investments away from carbon based fuels and toward new 
climate friendly energy technologies. We have to accelerate the 
progress underway and adopt policies in the next few years to turn the 
corner on our global warming emissions, if we are to avoid locking 
ourselves and future generations into a dangerously disrupted climate. 
Scientists are very concerned that we are very near this threshold now. 
Most say we must keep atmosphere concentrations of CO2 below 
450 parts per million, which would keep total warming below 2 degrees 
Celsius (3.6 degrees Fahrenheit). Beyond this point we risk severe 
impacts, including the irreversible collapse of the Greenland Ice Sheet 
and dramatic sea level rise. With CO2 concentrations now 
rising at a rate of 1.5 to 2 parts per million per year, we will pass 
the 450ppm threshold within two or three decades unless we change 
course soon.
    In the United States, a national program to limit carbon dioxide 
emissions must be enacted soon to create the market incentives 
necessary to shift investment into the least-polluting energy 
technologies on the scale and timetable that is needed. There is 
growing agreement between business and policy experts that quantifiable 
and enforceable limits on global warming emissions are needed and 
inevitable.\26\ To ensure the most cost-effective reductions are made, 
these limits can then be allocated to major pollution sources and 
traded between companies, as is currently the practice with sulfur 
emissions that cause acid rain. Further complimentary and targeted 
energy efficiency and renewable energy policies are critical to 
achieving CO2 limits at the lowest possible cost, but they 
are no substitute for explicit caps on emissions.
---------------------------------------------------------------------------
    \26\ U.S. Climate Action Partnership, http://www.us-cap.org.
---------------------------------------------------------------------------
    A coal integrated gasification combined cycle (IGCC) power plant 
with carbon capture and disposal can also be part of a sustainable path 
that reduces both natural gas demand and global warming emissions in 
the electricity sector. Methods to capture CO2 from coal 
gasification plants are commercially demonstrated, as is the injection 
of CO2 into geologic formations for disposal.\27\ On the 
other hand, coal gasification to produce a significant amount of 
liquids for transportation fuel would not be compatible with the need 
to develop a low-CO2 emitting transportation sector. 
Finally, gasifying coal to produce synthetic pipeline gas or chemical 
products needs a careful assessment of the full life cycle emission 
implications and the emission reductions that are required from those 
sectors before decisions are made to invest in these practices.
---------------------------------------------------------------------------
    \27\ David Hawkins, Testimony on S. 731 and S. 962: Carbon Capture 
and Sequestration before the Senate Energy and Natural Resources 
Committee, April 16, 2007. http://docs.nrdc.org/globalwarming/
glo_07041601A.pdf.

    The Chairman. All right. Thank you very much. That's very 
useful.
    Mr. Fulkerson, go right ahead.

STATEMENT OF WILLIAM FULKERSON, SENIOR FELLOW, INSTITUTE FOR A 
 SECURE AND SUSTAINABLE ENVIRONMENT, UNIVERSITY OF TENNESSEE, 
                         KNOXVILLE, TN

    Mr. Fulkerson. Mr. Chairman and members of the committee, I 
am very pleased to have been invited to testify at this hearing 
on coal gasification, synfuels, and related topics.
    What I'm going to say today derives mostly from what I 
consider to be the brilliant work of Bob Williams and his 
colleagues at Princeton University. I'm pinch-hitting for Bob 
today, since he is lecturing in China right now.
    The story Bob would have told you, however, I think is 
extremely important for the committee's deliberations. So, 
maybe my pinch-hitting, no matter how bad it is, is warranted.
    Let me give you a little background. Since retiring from 
the Oak Ridge National Laboratory in 1994, I have had the 
privilege of chairing a committee of people from 14 DOE 
National Labs, which we call the Laboratory Energy R&D Working 
Group, or LERDWG. We meet several times a year in Washington to 
talk about energy R&D policy, and about what's new and exciting 
in energy science and technology. At the April meeting of our 
group, Bob Williams talked about his idea for coal biomass 
gasification in a complex producing gasoline and diesel fuels 
via the Fischer-Tropsch synthesis process, as well as coal 
production of electricity and the sequestration of excess 
CO2 produced. This idea addresses the coupled 
problems that everybody has said already of oil security, or 
oil dependence, and climate change mitigation. I call this 
scheme biocoal fuels.
    By carefully matching the feedstocks of biomass and coal in 
this process, and capturing and storing the excess 
CO2, sufficient CO2 can be captured to 
offset the carbon in the product fuels that you produce--
conventional, diesel, and gasoline--and that's a big idea. 
That's a big idea.
    Why does that work? Well, it works, because most of the 
carbon in the biomass is sequestered. That's a net negative 
which offsets the emission of carbon from burning gasoline and 
diesel that you produce.
    Bob shows that if CO2, sequestered, has a value 
greater than, let's say, about $25 per ton, which is roughly 
the magnitude of the MIT report, where sequestration begins to 
become economically justified, then the process can produce 
competitive fuels at a competitive price, compared to 
petroleum, if oil prices are greater than $50 a barrel, which 
they're presently at, of course.
    Another really important part of this scheme is that the 
ratio of the biomass that you need--biomass energy input that 
you need to produce a unit of energy fuel output is about one 
or less, and that means that this process would be two or three 
times--could produce two or three times as much carbon-free 
fuel as, for example, cellulosic, enzymatic ethanol would 
produce. Now, this remarkable result derives from the fact that 
much of the energy to run the process, the overall process, 
comes from coal. This means that biomass resource productivity 
can be greatly expanded. In fact, Williams makes a very 
interesting thought experiment. He asks, ``What fraction of the 
transportation fuels from North America might his carbon-
neutral biocoal route provide?'' The answer is that all the 
fuels estimated to be required by 2050, for transportation of 
all sorts for North America, could be produced from the 
estimated 1.3 billion tons per year of biomass potentially 
available on a sustainable basis for energy, as estimated by 
the Department of Energy and the United States--and the USDA. 
This resource includes agricultural and forest residues, 
municipal waste, as well as biomass energy crops, the latter 
providing maybe 30 percent of the total resource to avoid 
excessive land use.
    But this can only be accomplished--as Dr. Herzog 
indicated--it can only be accomplished, however, if light-duty 
vehicle fleet has an average fuel efficiency of about 60 miles 
per gallon. I drove up in my Prius car, and I only got, well, 
close to 50 miles per gallon. So, can we get 60, on average, by 
2050? That's the question. So, that's one requirement.
    Also, such a huge syn-fuels thing, which, of course, is 
much bigger would double the current use of coal. But we're 
pretty rich in coal, if we can just solve the other 
environmental problems associated with increased use.
    Well, this is a rough summary of Bob Williams' great idea. 
I understand that he will submit written testimony to the 
committee to supply the details.
    The scheme depends, of course, on sequestered 
CO2 having a value--and that's up to you guys--and 
sequestration working at a large scale.
    Finally, in my written testimony, I list six policies 
suggested by Williams that I believe could encourage innovation 
in developing solutions to our coupled problems of oil 
dependence and climate change mitigation. The policies are 
designed to be largely technology-neutral to avoid picking 
winners. Of course, it's easy to make such a list. The hard 
work comes from sorting out the many options so that policies 
are effective, and that they're fair, and that they're 
politically possible. And I think that's your job, and it's a 
difficult one, and I don't envy you at all. But it is so 
important that you take on the challenge. And I'm glad to see 
you're doing it.
    [The prepared statement of Mr. Fulkerson follows:]
Prepared Statement of William Fulkerson, Senior Fellow, Institute for a 
Secure and Sustainable Environment, University of Tennessee, Knoxville, 
                                   TN
    Mr. Chairman and Members of the Committee, I am pleased to have 
been asked to testify at this hearing on coal gasification, synfuels 
and related topics. What I will say today derives mostly from the 
brilliant work of Bob Williams and his colleagues at Princeton 
University. I am pinch-hitting for Bob since he is lecturing in China 
today. What Bob and his colleagues have concluded from their analysis 
is very important to the issues being considered by this Committee. I 
believe he is right else I wouldn't be here.
    Since retiring from the Oak Ridge National Laboratory in 1994 I 
have had the pleasure of chairing a committee of people from 14 DOE 
national laboratories. It is called the Laboratory Energy R&D Working 
Group or LERDWG. We meet several times a year in Washington to talk 
about energy R&D policy and about what is new and exciting in energy 
science and technology. In fact staff from this Committee often come to 
our meetings.
    At our April meeting Bob Williams talked to us about his idea for a 
coal/biomass gasification complex producing gasoline and Diesel fuel 
via Fisher-Tropsch synthesis as well as co-production of electricity. 
Bob is interested in addressing the coupled challenges of oil security 
and climate change mitigation. Of course, liquid fuels from coal can be 
produced using oxygen blown gasification and Fisher-Tropsch, but this 
will result in about twice the amount of CO2 vented compared 
to producing the same quantity of fuels from petroleum. If petroleum 
costs $50/bbl or more this synfuels process can be competitive. If the 
excess CO2 produced is sequestered instead of vented then 
the coal synfuels process can be equivalent to petroleum in net 
CO2 emissions.
    But Williams points out we can do much better than petroleum if we 
gasify biomass with the coal in the same facility, and if the excess 
CO2 produced is captured and stored in deep saline aquifers 
or is used for enhanced oil recovery from depleted oil reservoirs. In 
fact, the CO2 captured and stored can be sufficient to 
offset the carbon in the fuel product so that the overall system 
including the carbon released by burning of the fuel produced can be a 
net zero in emissions. This is because most of the carbon in the 
biomass is captured as CO2 and is sequestered offsetting the 
carbon released in product fuel burning. Of course the carbon in the 
biomass is extracted from the air during its growing. Burning the fuel 
produced merely returns carbon to the atmosphere from whence it came, 
and the cycle is completed with no net additions to the atmosphere. So, 
Bob shows that if CO2 sequestered has a value of greater 
than $25/t the process can be competitive with fuels derived from 
petroleum if petroleum costs more than $50/bbl.
    Another important feature of this scheme is that the ratio of 
biomass energy input to product fuel energy output is of the order of 
unity. This means that 2-3 times as much fuel can be produced per unit 
of biomass energy as from the cellulosic ethanol enzymatic process, for 
example. This remarkable result derives from the fact that much of the 
energy to run the process comes from coal. This means that the biomass 
resource productivity can be greatly expanded.
    The productivity can be pushed even further by using mixed prairie 
grasses grown on carbon deficient soils as suggested in the recent 
paper in Science Magazine (Tilman, D., et al, Science, 314, 1598-1600, 
8 Dec. 2006). These researchers from the University of Minnesota found 
that mixed prairie grasses sequestered up to 0.6 kg of carbon in roots 
and soil per kg of prairie grass harvested and this can happen year 
after year since the grasses are perennials. Using mixed prairie grass 
as the biomass feedstock in the process requires only about 0.6 GJ of 
biomass per GJ of product fuel is required. This biomass productivity 
is most important because the biomass resource is limited.
    Williams makes a very interesting thought experiment. He asks what 
fraction of the transportation fuels for North America can his coal/
biomass/sequestration route provide. The answer is that all fuels 
estimated to be required by 2050 for transportation of all sorts could 
be produced from the estimated 1.3 B tones per year of biomass 
potentially available on a sustainable basis as estimated by DOE and 
USDA. This resource includes agricultural and forest residues and 
municipal waste as well as biomass energy crops. The latter provides 
only about 30% of the total resource. This can only be accomplished, 
however, if the light duty vehicle fleet has an average fuel efficiency 
of 60 mpg or greater by 2050, not an impossible target. Also, such a 
synfuels enterprise would double current use of coal.
    This is a rough summary of Bob Williams great idea. I understand 
that he will submit written testimony to the Committee to supply 
details. He has done very elaborate and detailed calculations for many 
variations on his theme.
    Finally, here is a set of policies suggested by Williams that I 
believe could encourage innovation in developing solutions to the 
coupled problems of oil security and climate change mitigation. The 
policies are designed to be largely technology independent to avoid 
picking winners.
    First, the greenhouse gas emission externality must be reduced by 
putting a cost on emissions by cap and trade or tax or whatever. The 
Congress through various pieces of legislation is actively considering 
this, and no doubt something will emerge.
    Second, a low-carbon fuel standard such as is being developed by 
the State of California should be adopted and existing subsidies on low 
carbon fuels should be discontinued.
    Third, regulations should be adopted to assure that no new coal 
synfuels plants are built without carbon capture and storage.
    Fourth, an oil security feebate might be enacted to put a floor on 
transportation fuel prices. If oil prices crash, say to $30/bbl from 
$60, transportation fuel could be taxed and part of the tax rebated to 
synfuels plants to help them compete and produce even with low world 
oil prices. Part of the tax revenues could be returned to the public.
    Fifth, regulations (such as improved CAFE standards) to promote 
more efficient use of transportation fuels need to be aggressively 
strengthened over time.
    Sixth, regulations and R&D to improve coalmine safety, worker 
health, and environmental improvement need to be periodically reviewed 
and upgraded if necessary.
    Of course it is easy to make such a list. The hard work comes in 
sorting out the many options so policies are effective, fair and 
politically possible. I think that is your job, and it is a difficult 
one.

    The Chairman. Thank you very much for your testimony.
    Mr. Bartis, go right ahead.

   STATEMENT OF JAMES BARTIS, SENIOR POLICY RESEARCHER, RAND 
                   CORPORATION, ARLINGTON, VA

    Mr. Bartis. Mr. Chairman and distinguished members, thank 
you for inviting me to testify. My remarks today are based on 
RAND research, some of which is ongoing, sponsored by the 
National Energy Technology Laboratory, the United States Air 
Force, the Federal Aviation Administration, and the National 
Commission on Energy Policy.
    Congress has before it the two major energy challenges: 
first, what to do about large well transfers from oil consumers 
to OPEC; and second, how can we reduce our greenhouse gas 
emissions?
    OPEC revenues from oil exports are currently about $500 
billion per year, and are heading higher. These high revenues 
raise serious national security concerns because some of the 
OPEC member states are governed by regimes that are not 
supportive of U.S. foreign policy objectives. Oil revenues have 
been, and are being, used to purchase weapons. Moreover, the 
higher oil prices rise, the greater the chances that oil 
importing countries will pursue special relationships with oil 
exporters and defer joining the United States in multilateral 
diplomatic efforts. We see this happening right now in South 
America and Africa.
    No less pressing is the importance of addressing the threat 
of global climate change. For example, as you just heard, 
without measures to address carbon dioxide emissions, the use 
of coal-derived liquids to displace petroleum fuels for 
transportation will roughly double greenhouse gas emissions. 
This is clearly not acceptable.
    The emphasis of RAND's research on unconventional fuels has 
been on these two potentially conflicting policy objectives. We 
have concentrated our efforts on coal-to-liquids because that 
option is one of the only two approaches that are commercially 
ready and capable of displacing significant amounts of imported 
petroleum. The only other technical option that meets these 
criteria is ethanol production from food crops. Moreover, only 
the coal-to-liquids approach produces a fuel suitable for use 
in heavy-duty trucks, railroad engines, commercial aircraft, or 
military vehicles and weapons systems.
    When we look to the future, the only near-term, low-risk 
option beyond the two I just mentioned is a variance of the 
same technology that is used for producing liquids from coal; 
namely, gasification, in Fischer-Tropsch synthesis, as applied 
to biomass, such as crop residues or a combination of biomass 
and coal, as just discussed by Mr. Fulkerson.
    Producing large amounts of coal-derived liquid fuels will 
cause world oil prices to decrease. Our research shows that, 
under reasonable assumptions, this price reduction effect could 
be very large and would likely result in large benefits to U.S. 
consumers and large decreases in OPEC revenues. Savings by the 
average household in the United States would range from a few 
hundred to a few thousand dollars per year. OPEC export 
revenues could decrease by hundreds of billions of dollars per 
year.
    We also examined whether a coal-to-liquids industry can be 
developed consistent with the need to manage carbon dioxide 
emissions. If we are willing to accept emission levels that are 
similar to those associated with conventional petroleum, the 
answer is definitely yes.
    Two technical approaches are available that allow this 
level of control: the first involves the capture and geological 
sequestration of carbon dioxide at the plant site. This 
approach appears feasible, but it has not been proven, and it 
will not be proven until multiple large-scale demonstrations 
are successfully conducted, and fortunately, the second 
approach is a very low-risk approach; namely, using a 
combination of coal and biomass, as you just heard, in a 
Fischer-Tropsch plant. Now, given the large demand on OPEC oil 
that we anticipate over the next 50 years, this is a great 
answer. We can at least address a major economic and national 
security problem while not worsening environmental impacts.
    If, however, we demand a significant reduction in emission 
levels, as compared to conventional petroleum, the answer is a 
qualified yes. The only way we know of reaching this level of 
carbon dioxide control when making coal-derived liquids is to 
use the combination of coal and biomass, and to capture and 
sequester most of the carbon dioxide generated at the plant 
site. The reason I give a qualified yes is that there does 
remain considerable uncertainty regarding the viability of 
sequestering carbon dioxide in geological formations.
    Stepping back a bit, we have, at RAND, reviewed the 
prospects of coal-to-liquids production in the United States, 
and we see three major uncertainties that are impeding private-
sector investment.
    The first uncertainty centers on the cost and performance 
of coal-to-liquid plants. Our current best estimate is that 
coal-to-liquids production is not competitive unless crude oil 
prices are in the range of $50 to $60 per barrel. However, this 
estimate is based on highly conceptual engineering designs that 
are only intended to provide a rough estimate of costs. At 
RAND, we have learned that, when it comes to cost estimates, it 
is often the case that the less you know, the more attractive 
the course.
    The second uncertainty concerns the future direction of 
world oil prices. The third uncertainty, I've already touched 
upon is namely, whether, and how greenhouse gas emissions might 
be controlled in the United States.
    Just as these three uncertainties are impeding private 
sector investment, they should also deter an immediate national 
commitment to rapidly put in place a multimillion-barrel-per-
day coal-to-liquids industry. However, the traditional hands-
off, or research-only, approach is not commensurate with the 
continuing adverse economic, national security, and global 
environmental consequences of relying on imported petroleum. 
For these reasons, Congress should consider a middle path that 
focuses on reducing uncertainties and fostering early 
commercial experience by: No. 1, providing Federal cost-sharing 
of front-end engineering designs for a few commercial plants; 
and No. 2, promoting the construction and operations of a 
limited number of commercial-scale plants by establishing a 
flexible incentive program capable of attracting the 
participation of America's top technology firms. We 
characterize this middle path as an insurance strategy, since, 
for modest payments, it significantly improves the ability of 
the private sector to respond officially to future market 
developments as both government and industry learn more about 
the future course of world oil prices and as the policy and 
technical mechanisms for carbon management become clearer.
    Thank you very much.
    [The prepared statement of Mr. Bartis follows:]

  Prepared Statement of James T. Bartis,\1\ Senior Policy Researcher, 
                    RAND Corporation, Arlington, VA
            Policy Issues for coal-to-Liquid Development\2\
    Chairman and distinguished Members: Thank you for inviting me to 
speak on the potential use of our nation's coal resources to produce 
liquid fuels. I am a Senior Policy Researcher at the RAND Corporation 
with over 25 years of experience in analyzing and assessing energy 
technology and policy issues. At RAND, I am actively involved in 
research directed at understanding the costs and benefits associated 
with alternative approaches for promoting the use of coal and other 
domestically abundant resources, such as oil shale and biomass, to 
lessen our nation's dependence on imported petroleum. Various aspects 
of this work are sponsored and funded by the National Energy Technology 
Laboratory (NETL) of the U.S. Department of Energy, the United States 
Air Force, the Federal Aviation Administration, and the National 
Commission on Energy Policy.
---------------------------------------------------------------------------
    \1\ The opinions and conclusions expressed in this testimony are 
the author's alone and should not be interpreted as representing those 
of RAND or any of the sponsors of its research. This product is part of 
the RAND Corporation testimony series. RAND testimonies record 
testimony presented by RAND associates to federal, state, or local 
legislative committees; government-appointed commissions and panels; 
and private review and oversight bodies. The RAND Corporation is a 
nonprofit research organization providing objective analysis and 
effective solutions that address the challenges facing the public and 
private sectors around the world. RAND's publications do not 
necessarily reflect the opinions of its research clients and sponsors.
    \2\ This testimony is available for free download at http://
www.rand.org/pubs/testimonies/CT281.
---------------------------------------------------------------------------
    Today, I will discuss the key problems and policy issues associated 
with developing a domestic coal-to-liquids industry and the approaches 
Congress can take to address these issues. My key conclusions are as 
follows. First, successfully developing a coal-to-liquids industry in 
the United States would bring significant economic and national 
security benefits by reducing wealth transfers to oil-exporting 
nations. Second, the production of petroleum substitutes from coal may 
cause a significant increase in carbon dioxide emissions; however, 
technical approaches exist that could lower carbon dioxide emissions to 
levels well below those associated with producing and using 
conventional petroleum. Third, without federal assistance, private-
sector investment in coal-toliquids production plants is unlikely to 
occur, because of uncertainties about the future of world oil prices, 
the costs and performance of initial commercial plants, and the 
viability of carbon management options. Finally, a federal program 
directed at reducing these uncertainties and obtaining early, but 
limited, commercial experience appears to offer the greatest strategic 
benefits, given both economic and national security benefits and the 
uncertainties associated witheconomic viability and environmental 
performance, most notably the control of greenhouse gas emissions.
    Some of the topics I will be discussing today are supported by 
research that RAND has only recently completed; consequently, the 
results have not yet undergone the thorough internal and peer reviews 
that typify RAND research reports. Out of respect for this Committee 
and the sponsors of this research, and in compliance with RAND's core 
values, I will only present findings in which RAND and I have full 
confidence at this time.
Coal Gasification and Liquid Fuels Production
    There are two major approaches for using coal to produce liquid 
transportation fuels: direct liquefaction and the Fischer-Tropsch (F-T) 
processes. Both processes were developed in pre-World War II Germany 
and both were used, but on fairly small scales, to meet Germany's and 
Japan's wartime needs for fuel. In the direct liquefaction approach, 
hydrogen is added directly to the organic structure of coal at high 
pressures and temperatures. At present, a large first-of-a-kind 
commercial plant based on direct liquefaction is being built in China. 
Pending the completion and successful operation of that plant, we do 
not anticipate that there will be industrial interest in the direct 
liquefaction approach within the United States. For this reason, I will 
confine my remarks to the F-T process, which is the focus of 
considerable industrial interest in the United States.
    In the F-T approach, coal is first gasified to produce a mixture 
that consists mostly of three gases: carbon monoxide, hydrogen, and 
carbon dioxide. This gas mixture is further processed to remove carbon 
dioxide, as well as trace contaminants, and the resulting mixture of 
clean hydrogen and carbon monoxide is sent to a chemical reactor where 
the gaseous mixture is catalytically converted to liquid products. 
After a moderate amount of fuel processing that would be performed on-
site, a commercial F-T plant would produce a near-zero sulfur, high-
performance diesel fuel for automotive applications and a near-zero 
sulfur jet fuel that can be used for commercial aviation applications 
or in military weapon systems. Between a third and one half of the 
product of commercial F-T coal-to-liquid plants would be a mixture of 
liquids that can be used to manufacture motor gasoline, either at the 
F-T plant site or at nearby refineries.
    Since the end of World War II, the only commercial experience in F-
T coal-to-liquids production has occurred in South Africa under 
government subsidy. In particular, a South African plant constructed in 
the early 1980s currently produces fuels and chemicals that are the 
energy equivalent of about 160,000 barrels per day of oil.
    An interesting feature of the F-T approach to liquid fuels 
production is that it is not limited to coal. For example, large 
commercial F-T plants producing liquid fuels from natural gas are 
operating in Malaysia, Qatar, and South Africa. Other options are to 
use biomass or a combination of coal and biomass as the feedstock 
instead of straight coal. While these options are not being used on 
acommercial scale, our assessment of approaches using biomass or a 
combination of coal and biomass is that they involve very limited, low-
risk technology development. As I elaborate on below, these two 
approaches involving biomass offer liquid fuels production and use that 
entail near-zero emissions of carbon dioxide.
Technical Readiness and Production Potential
    As part of RAND's examination of coal-to-liquids fuels development, 
we have reviewed the technical, economic, and environmental viability 
and production potential of a range of options for producing liquid 
fuels from domestic resources. If we focus on unconventional fuel 
technologies that are now ready for large-scale commercial production 
and that can displace at least a million barrels per day of imported 
oil, we find only two candidates: grain-derived ethanol and F-T coal-
toliquids. Moreover, only the F-T coal-to-liquids candidate produces a 
fuel that is suitable for use in heavy-duty trucks, railroad engines, 
commercial aircraft, or military vehicles and weapon systems. If we 
expand our time horizon to consider technologies that might be ready 
for use in initial commercial plants within the next five years, only 
one or two new technologies become available: the in-situ oil shale 
approaches being pursued by a number of firms and the F-T approaches 
for converting biomass or a combination of coal and biomass to liquid 
fuels. We have also looked carefully at the development prospects for 
technologies that offer to produce alcohol fuels from sources other 
than food crops, so-called cellulosic materials. Our finding is that 
while this is an important area for research and development, the 
technology base is not yet sufficiently developed to support an 
assessment that alcohol production from cellulosic materials will be 
competitive with F-T biomass-to-liquid fuels within the next ten years, 
if ever.
The Strategic Benefits of Coal-to-Liquids Production
    As part of RAND's examination of coal-to-liquid fuels development, 
our research is addressing the strategic benefits of having in place a 
mature coal-to-liquid fuels industry producing millions of barrels of 
oil per day. If coal-derived liquids were added to the world oil 
market, such liquids would cause world oil prices to be lower than what 
would be the case if they were not produced. This effect occurs 
regardless of what fuel is being considered. It holds for coal-derived 
liquids and for oil shale, heavy oils, tar sands, and biomass-derived 
liquids, as well as, for that matter, additional supplies of 
conventional petroleum. The price reduction effect also occurs when oil 
demand is reduced through fiscal measures, such as taxes on oil, or 
through the introduction of advanced technologies that use less 
petroleum, such as higher mileage vehicles. Moreover, this reduction in 
world oil prices is independent of where such additional production or 
energy conservation occurs, as long as the additional production is 
outside of OPEC and OPEC-cooperating nations.
    In a 2005 analysis of the strategic benefits of oil shale 
development, RAND estimated that 3 million barrels per day of 
additional liquid fuels production would yield a world oil price drop 
of between 3 and 5 percent.\3\ Our ongoing research supports that 
estimated range and shows that the price drop increases in proportion 
to production increases. For instance, an increase of 6 million barrels 
per day would likely yield a world oil price drop of between 6 and 10 
percent. This more recent research also shows that even larger price 
reductions may occur in situations in which oil markets are 
particularly tight or in which OPEC is unable to enforce a profit-
optimizing response among its members.
---------------------------------------------------------------------------
    \3\ Oil Shale Development in the United States: Prospects and 
Policy Issues, Santa Monica, CA: RAND MG414-NETL, 2005.
---------------------------------------------------------------------------
    This anticipated reduction in world oil prices yields important 
economic benefits. In particular, American consumers would pay tens of 
billions of dollars less for oil or, under some future situations, 
hundreds of billions of dollars less for oil per year. On a per-
household basis, we estimate that the average annual benefit would 
range from a few hundred to a few thousand dollars.
    This anticipated reduction in world oil prices associated with 
coal-to-liquids development also yields a major national security 
benefit. At present, OPEC revenues from oil exports are about $500 
billion per year. Projections of future petroleum supply and demand 
published by the Department of Energy indicate that unless measures are 
taken to reduce the prices of, and demand for, OPEC petroleum, such 
revenues will grow considerably. These high revenues raise serious 
national security concerns, because some OPEC member nations are 
governed by regimes that are not supportive of U.S. foreign policy 
objectives. Income from petroleum exports has been used by unfriendly 
nations, such as Iran and Iraq under Saddam Hussein, to support weapons 
purchases, or to develop their own industrial base for munitions 
manufacture. Also, the higher prices rise, the greater the chances that 
oil-importing countries will pursue special relationships with oil 
exporters and defer joining the United States in multilateral 
diplomatic efforts.
    Our research shows that developing an unconventional fuels industry 
that displaces millions of barrels of petroleum per day will cause a 
significant decrease in OPEC revenues from oil exports. This decrease 
results from a combination of lower prices and a lower demand for OPEC 
production. The size of this reduction in OPEC revenues is determined 
by the volume of unconventional fuels produced and future market 
conditions, but our ongoing research indicates that annual reductions 
of hundreds of billions of dollars are not unreasonable. The 
significant reduction in wealth transfers to OPEC and the geopolitical 
consequences of reduced demand for OPEC oil represent the major 
national security benefits associated with the development of an 
unconventional liquid fuels production industry.
    The above-described strategic benefits derive from the existence of 
the OPEC cartel. The favorable benefits of reduced oil prices accrue to 
our nation as a whole; however, they are not captured by the private 
firms that would invest in coal-to-liquids development.
The Direct Benefits of Coal-to-Liquids Production
    Beyond the strategic benefits for the nation associated with coal-
to-liquids production are certain direct benefits. If coal-derived 
liquid fuels can be produced at prices well below world oil prices, 
then the private firms that invest in coal-derived liquid fuels 
development could garner economic profits above and beyond what is 
considered a normal return on their investments. Through taxes on these 
profits and, in some cases, lease and royalty payments, we estimate 
that roughly 35 percent of these economic profits could go to federal, 
state, and local governments and, thereby, broadly benefit the public.
    A second direct benefit derives from the broad regional dispersion 
of the U.S. coal resource base and the fact that coal-to-liquids plants 
are able to produce finished motor fuel products that are ready for 
retail distribution. As such, developing a coal-to-liquids industry 
should increase the resiliency of the overall petroleum supply chain.
    The remaining direct benefits of developing a coal-to-liquids 
production industry are local or regional, as opposed to national. In 
particular, coal-to-liquids industrial development offers significant 
opportunities for economic development and would increase employment in 
coal-rich states.
Greenhouse Gas Emissions
    Given the Committee's interest in greenhouse gas emissions, I limit 
my remarks to that topic and simply point out that the environmental 
impacts associated with certain types of coal mining and water usage 
requirements, especially in the West, may limit the number of locations 
at which F-T coal-to-liquid plants can be operated.
    If no provisions are in place to manage carbon dioxide emissions, 
then the use of F-T coal-toliquids fuels to displace petroleum fuels 
for transportation uses will roughly double greenhouse gas emissions. 
This finding is relevant to the total fuel lifecycle, i.e., well-to-
wheels or coal-mine-to-wheels. This increase in greenhouse gas 
emissions is primarily attributable to the large amount of carbon 
dioxide emissions that come from a F-T coal-to-liquids production plant 
relative to a conventional oil refinery. In fact, looking solely at the 
combustion of F-T derived fuel as opposed to its production, our 
analyses show that combustion of an F-T coal-derived fuel would produce 
somewhat, although not significantly, lower greenhouse gas emissions 
relative to the combustion of a gasoline or diesel motor fuel prepared 
by refining petroleum.
    In our judgment, the high greenhouse gas emissions of F-T coal-to-
liquids plants that do not manage such emissions preclude their 
widespread use as a means of displacing imported petroleum. We now turn 
to some options for managing greenhouse gas emissions.
Options for Managing Greenhouse Gas Emissions
    For managing greenhouse gas emissions for F-T coal-to-liquid 
plants, RAND examined three options: (1) carbon capture and 
sequestration, (2) carbon dioxide capture and use in enhanced oil 
recovery, and (3) gasification of both coal and biomass followed by F-T 
synthesis of liquid fuels. We discuss each below in turn.
    Carbon Capture and Sequestration.--By carbon capture and 
sequestration, I refer to technical approaches being developed in the 
United States, primarily through funding from the U.S. Department of 
Energy, and abroad that are designed to capture carbon dioxide produced 
in coal-fired power plants and sequester that carbon dioxide in various 
types of geological formations, such as deep saline aquifers. This same 
approach can be used to capture and sequester carbon dioxide emissions 
from F-T coal-to-liquids plants and from F-T plants operating on 
biomass or a combination of coal and biomass. When applied to F-T coal-
to-liquids plants, carbon capture and sequestration should cause 
``mine-to-wheels'' greenhouse gas emissions to drop to levels 
comparable to the ``well-to-wheels'' emissions associated with 
conventional petroleum-derived motor fuels. Moreover, any incentive 
adequate to promote carbon capture at coal-fired power plants should be 
equally, if not more, effective in promoting carbon capture at F-T 
plants producing liquid fuels.
    The U.S. Department of Energy program on carbon capture and 
sequestration appears to be well managed and has made considerable 
technical progress. However, considering the continued and growing 
importance of coal for both power and liquids production and the 
potential adverse impacts of greenhouse gas emissions, we believe this 
program has been considerably underfunded. While we are optimistic that 
carbon capture and geologic sequestration can be successfully developed 
as a viable approach for carbon management, we also recognize that 
successful development constitutes a major technical challenge and that 
the road to success requires multiple, large-scale demonstrations that 
go well beyond the current DOE plans and budget for the efforts that 
are now under way.
    Carbon Capture and Enhanced Oil Recovery.--In coal-to-liquids 
plants, about 0.8 tons of carbon dioxide are produced along with each 
barrel of liquid fuel. For coal-to-liquids plants located near 
currently producing oil fields, this carbon dioxide can be used to 
drive additional oil recovery. We anticipate that each ton of carbon 
dioxide applied to enhanced oil recovery will cause the additional 
production of 2 to 3 barrels of oil, although this ratio depends highly 
on reservoir properties and oil prices. Based on recent studies 
sponsored by the U.S. Department of Energy, opportunities for enhanced 
oil recovery provide carbon management options for at least a half 
million barrels per year of coal-to-liquids production capacity. A 
favorable collateral consequence of this approach to carbon management 
is that a half million barrels per day of coal-to-liquids production 
will promote additional domestic petroleum production of roughly 1 
million barrels per day.
    The use of pressurized carbon dioxide for enhanced oil recovery is 
a well-established practice in the petroleum industry. Technology for 
capturing carbon dioxide at a coal-to-liquids plant is also well 
established. There are no technical risks, but questions do remain 
about methods to optimize the fraction of carbon dioxide that would be 
permanently sequestered.
    Combined Gasification of Coal and Biomass.--Non-food crop biomass 
resources suitable as feedstocks for F-T biomass-to-liquid production 
plants include mixed prairie grasses, switch grass, corn stover and 
other crop residues, forest residues, and crops that might be grown on 
dedicated energy plantations. When such biomass resources are used to 
produce liquids through the F-T method, our research shows that 
greenhouse gas emissions should be well below those associated with the 
use of conventional petroleum fuels. Moreover, when a combination of 
coal and biomass is used, for example, a 50-50 mix, we estimate that 
net carbon dioxide emissions will be comparable to or, more likely, 
lower than well-to-wheels emissions of conventional petroleum-derived 
motor fuels. Finally, we have examined liquid fuel production concepts 
in which carbon capture and sequestration is combined with the combined 
gasification of coal and biomass. Our preliminary estimate is that a 
50-50 coal-biomass mix combined with carbon capture and sequestration 
should yield zero, and possibly negative, carbon dioxide emissions. In 
the case of negative emissions, the net result of producing and using 
the fuel would be the removal of carbon dioxide from the atmosphere.
    One perspective on the combined gasification of coal and biomass is 
that biomass enables F-T coal-to-liquids, in that the combined 
feedstock approach provides an immediate pathway to unconventional 
liquids with no net increase in greenhouse gas emissions, and an 
ultimate vision, with carbon capture and sequestration, of zero net 
emissions. Another perspective is that coal enables F-T biomass-to-
liquids, in that the combined approach reduces overall production costs 
by reducing fuel delivery costs, allowing larger plants that take 
advantage of economies of scale, and smoothing over the inevitable 
fluctuations in biomass availability associated with annual and multi-
year fluctuations in weather patterns, especially rainfall.
Prospects for a Commercial Coal-to-Liquids Industry
    The prospects for a commercial coal-to-liquids industry in the 
United States remain unclear. Three major impediments block the way 
forward:

          1. Uncertainty about the costs and performance of coal-to-
        liquids plants;
          2. Uncertainty about the future course of world oil prices;
          3. Uncertainty about whether and how greenhouse gas 
        emissions, especially carbon dioxide emissions, might be 
        controlled in the United States.

    As part of our ongoing work, RAND researchers have met with a 
number of firms that are promoting coal-to-liquids development or that 
clearly have the management, financial, and technical capabilities to 
play a leading role in developing of a commercial industry. Our 
findings are that the three uncertainties noted above are impeding and 
will continue to impede private-sector investment in a coal-to-liquids 
industry unless the government provides fairly significant financial 
incentives, especially incentives that mitigate the risks of a fall in 
world oil prices.
    But just as these three uncertainties are impeding private-sector 
investment, they should also deter an immediate national commitment to 
establish rapidly a multi-million-barrel-per-day coal-to-liquids 
industry. However, the traditional hands-off or ``research only'' 
approach is not commensurate with continuing adverse economic, national 
security, and global environmental consequences of relying on imported 
petroleum. For this reason, Congress should consider a middle path to 
developing a coal-to-liquids industry, which focuses on reducing 
uncertainties and fostering early operating experience by promoting the 
construction and operation of a limited number of commercial-scale 
plants. We consider this approach an ``insurance strategy,'' in that it 
is an affordable approach that significantly improves the national 
capability to build a domestic unconventional fuels industry as 
government and industry learn more about the future course of world oil 
prices and as the policy and technical mechanisms for carbon management 
become clearer.
    Designing, building, and gaining early operating experience from a 
few coal-to-liquids plants would reduce the cost and performance 
uncertainties that currently impede private-sector investments. At 
present, the knowledge base for coal-to-liquid plant construction costs 
and environmental performance is very limited. Our current best 
estimate is that coal-to-liquids production from large first-of-a-kind 
commercial plants is competitive when crude oil prices average in the 
range of $50 to $60 per barrel. However, this estimate is based on 
highly conceptual engineering design analyses that are only intended to 
provide a rough estimate of costs. At RAND, we have learned that, when 
it comes to cost estimates, typically the less you know, the more 
attractive the costs. Details are important, and they are not yet 
available. For this reason, we believe that it is essential that the 
Department of Energy and Congress have access to the more reliable 
costing that is generally associated with the completion of a front-end 
engineering design.
    Early operating experience would promote post-production learning, 
leading to future plants with lower costs and improved performance. 
Post-production cost improvement--sometimes called the learning curve--
plays a crucial role in the chemical process industry, and we 
anticipate that this effect will eventually result in a major reduction 
of the costs of coal-derived liquid fuels. Most important, by reducing 
cost and performance uncertainties and production costs, a small number 
of early plants could form the basis of a rapid expansion of a more 
economically competitive coalto-liquids industry, depending on future 
developments in world oil markets.
Options for Federal Action
    The Federal government could take several productive measures to 
address the three major uncertainties noted above--production risks, 
market risks, and global warming--so that industry can move forward 
with a limited commercial production program consistent with an 
insurance strategy. A key step, as noted above, is reducing 
uncertainties about plant costs and performance by encouraging the 
design, construction, and operation of a few coal-to-liquid plants. An 
engineering design adequate to obtain a confident estimate of costs, to 
establish environmental performance, and to support federal, state, and 
local permitting requirements will cost roughly $30 million. The 
Federal government should consider cost-sharing options that would 
promote the development of a few site-specific designs. The information 
from such efforts would also provide Congress with a much stronger 
basis for designing broader measures to promote unconventional fuel 
development.
    At present, RAND is analyzing alternative incentive packages for 
promoting early commercial operating experience. In this analysis of 
incentives, we are examining not only the extent that the incentive 
motivates private-sector investment but also the potential impact on 
federal expenditures over a broad range of potential future outcomes. 
At this time, we are able to report that more attractive incentive 
packages generally involve a combination of the following three 
mechanisms: (1) a reduction in front-end investment costs, such as what 
would be offered by an investment tax credit; (2) a reduction in 
downside risks by a floor price guarantee; and (3) a sharing of upside 
benefits such as what would be offered by a profit sharing agreement 
between the government and producers when oil prices are high enough to 
justify such sharing. We also caution against the use of federal loan 
guarantees. Firms with the technical and management wherewithal to 
build and operate first-of-a-kind coal-to-liquids plants--and then move 
forward with subsequent plants--generally have access to needed 
financial resources. Loan guarantees can induce the participation of 
less capable firms, while isolating the project developer from the 
risks associated with cost overruns and shortfalls in plant 
performance. The public then ends up absorbing the costs if the project 
fails.
    Given the importance of controlling greenhouse gas emissions, it is 
appropriate that Congress demand that the initial round of commercial 
plants receiving government incentives employ carbon management 
approaches so that net greenhouse gas emissions are at least comparable 
to those anticipated from refining and using motor fuels derived from 
conventional petroleum.
    If the Federal government is prepared to promote early production 
experience, then expanded federal efforts in other areas would also be 
needed. Most important, consideration should be given to accelerating 
the development and testing (including large-scale testing) of methods 
for the longterm sequestration of carbon dioxide. This could involve 
using one or more of the early coal-to-liquids production plants as a 
source of carbon dioxide for the testing of sequestration options.
    At present, federal support for research on F-T approaches for 
liquids production is minimal. A near-term technology development 
effort designed to establish the commercial viability of a few 
techniques for the combined use of coal and biomass in a F-T liquids 
facility could offer significant cost and environmental payoffs. In 
promoting the production of alcohol fuels from cellulosic feedstocks, 
the federal government is making major R&D investments. In our 
judgment, the appropriate approach to balance this fuels production 
portfolio is not to lower the investment in cellulosic conversion, but 
rather to significantly increase the investment in F-T approaches, 
including coal, biomass, and combined coal and biomass gasification. 
This research investment should also include high-risk, high-payoff 
opportunities for cost reduction and improved environmental 
performance. Such efforts would significantly enhance the learning/cost 
reduction potential associated with early production experience. Such 
longer-term research efforts would also support the training of 
specialized scientific and engineering talent required for long-term 
progress.
    In closing, I commend the Committee for addressing the important 
and intertwined topics of reducing demand for crude oil and reducing 
greenhouse gas emissions. The United States has before it many 
opportunities--including coal and oil shale, renewables, improved 
energy efficiency, and fiscal and regulatory actions--that can promote 
greater energy security. Coal-to-liquids and more generally F-T 
gasification processes can be important parts of the portfolio as the 
nation responds to the realities of world energy markets, the presence 
of growing energy demand, and the need to protect the environment.

    The Chairman. Thank you very much.
    Mr. Denton, go right ahead.

  STATEMENT OF DAVID DENTON, DIRECTOR, BUSINESS DEVELOPMENT, 
      EASTMAN GASIFICATION SERVICES COMPANY, KINGSPORT, TN

    Mr. Denton. Mr. Chairman and distinguished members of the 
Committee, thank you for inviting Eastman Chemical Company to 
share its views regarding the opportunities and challenges of 
industrial gasification, meaning the gasification driving 
production of industrial chemicals or products.
    I'm David Denton, director of business development for 
Eastman Gasification Services Company, a wholly owned 
subsidiary of Eastman Chemical Company. I'm a chemical engineer 
by profession, have worked in a number of technical and 
management positions within Eastman's research and technology 
organizations for the past 32 years. I also hold the title of 
technology fellow within Eastman.
    In my present position, I identify and develop customers 
and project opportunities for our gasification business, and 
coordinate the public policy and technology initiatives.
    My company, Eastman Chemical, manufactures and markets 
chemicals, fibers, and plastics worldwide. We were founded in 
1920, headquartered in Kingsport, Tennessee. We're a Fortune 
500 company with 2006 sales of $7.5 billion, and approximately 
11,000 employees. Approximately 7,000 of those are employed in 
Senator Corker's State, and another 2,600 are located elsewhere 
in the United States. We are a U.S. company.
    The chemicals industry, as a whole, employs nearly 900,000 
people in the United States in high-paying jobs. There are an 
additional 4.5 million jobs in the chemical industry supply 
chain and services industries.
    Natural gas is the key feedstock for the production of most 
chemicals. Unfortunately, the rapid increase in natural gas 
prices this decade puts the majority of domestic chemical 
industry jobs at great risk. To put the price increase in 
perspective, natural gas prices have risen 41 percent more than 
gasoline prices since the year 2000. We all know how much 
gasoline has risen. The NYMEX price for January delivery is 35 
percent higher than today's price for natural gas.
    Electric generation has surpassed the chemical industry 
this decade as the largest consumer of natural gas. Natural gas 
use in electric generation has increased by 75 percent over the 
past 10 years, and now accounts for 27 percent of all electric 
generation, more than nuclear.
    Environmental considerations, particularly greenhouse gas 
reduction, will inevitably drive natural gas demand and prices 
even higher in the future. These rising natural gas prices 
ripple through the economy. Chemicals, food, packaging, steel, 
glass, all cost more when natural gas prices go up and jobs in 
these industries decline. In the ammonia-based fertilizer 
industry, for example, 50 percent of our jobs have been lost 
this decade to countries with lower natural gas cost 
components, countries such as Russia and those in the Middle 
East.
    The committee should do all it can to increase natural gas 
supplies in an environmentally sustainable way. Under any 
circumstances, however, the United States must move to develop 
substitutes for natural gas from domestic resources that are 
clean, inexpensive, plentiful, readily available, and secure.
    Eastman has extensive experience developing and using just 
such a substitute, and that is gasified coal. We pioneered the 
first commercial U.S. chemicals-from-coal facility in 1983 at 
our site in Kingsport, Tennessee. Our east coal gasification 
operating performance is industry-leading and highly regarded 
worldwide. Our forced outage rate has averaged less than 2 
percent since initial startup. This availability record of 
greater than 98 percent for over two decades of operation is 
exceptional for any coal-fed facility. Today, Eastman operates 
its gas fires with the highest syngas output per unit volume of 
any GE syn-gasifier in the world, and has over 600 person-years 
of combined operating experience in coal gasification. We're 
confident enough in coal gasification and its ability to 
develop high-valued products that in November of last year our 
chairman and CEO, Brian Ferguson, announced to the financial 
markets that we intend to drive at least 50 percent of our 
product volume from coal or feedstock within the next 10 years.
    Gasification, particularly industrial gasification of coal 
and other feedstocks, presents great opportunities for reduced 
natural gas demand, and, consequently, to reduce prices for all 
domestic consumers. The potential benefits for U.S. jobs 
preservation, our economy, trade balance, energy security, and 
the environment are tremendous. Our gasification is a very 
general term. It's not a single technology. There are many 
different gasifiers and gasification concepts.
    There are fundamental differences between gasification 
technology systems suitable for industrial gasification 
applications and those suitable for standalone power 
generation, or IGCC. These differences have significant 
implications for total system efficiencies and for the 
readiness to separate carbon from other constituents in the 
syngas stream.
    Industrial-based gasification systems, such as Eastman's 
facility, are designed, inherently and specifically, to capture 
carbon as part of their product stream. Typically, over 90 
percent of any CO2 in an industrial synthesis gas 
stream is captured because downstream process steps require it. 
The cost of this capture is thus included in the price of the 
final industrial products. This is unlike industrial 
gasification processes. Gasifiers designed for power generation 
do not currently separate CO2 or carbon from the 
syngas stream because there is no current economic reason or 
process requirements to do so. I believe that carbon capture 
for these power systems will be economically acceptable in the 
future, driven by market forces, R&D improvements, and 
regulatory requirements, but IGCC systems today don't have the 
ability and the equipment to capture CO2, as do 
industrial gasifiers.
    In my written statement, I've identified a number of unique 
characteristics of industrial gasification processes that 
inherently enable or advantage high levels of carbon capture. 
In addition to these technology distinctions, much of America's 
chemical industry infrastructure is located in, or near, 
geographic regions where carbon sequestration may present a 
win-win opportunity with enhanced oil recovery.
    So, industrial gasification systems prevent real and high-
value opportunities with respect to carbon capture and geologic 
sequestration.
    At the risk of using an overworked phrase, industrial 
gasification represents the low-hanging fruit, as the Congress 
and administration consider a program to test and develop 
carbon capture and sequestration technologies, protocols, 
regulations, and financing issues in commercial settings.
    Industrial gasification opportunities represent the logical 
economic and technological path forward to achieve four policy 
objectives I believe are key to America's economic and 
environmental health. Those are cost-effective environmental 
protection, energy security through the reliance on domestic 
fuel resources, reduction of natural gas prices and price 
volatility to all consumers, and global competitiveness and the 
preservation and expansion of millions of high-technology jobs 
in America's industrial sector.
    As promising as industrial gasification is for the policy 
objectives above, deployment of commercial plants will not 
occur, and the proving ground for carbon capture and 
sequestration will not be available, unless Federal and State 
governments provide the necessary incentives and framework to 
attract these first-adopter projects.
    As the MIT future coal study correctly points out, in our 
view, similar incentives, such as production tax credits, 
should be applied to carbon capture and geologic sequestration. 
There are considerable market, legal, and regulatory hurdles to 
be overcome or addressed before these first-adopters can 
attempt carbon sequestration, particularly in deep saline 
aquifers. However, doing so now could have significant benefits 
for the entire Nation.
    Federal incentives necessary to stimulate carbon capture 
and sequestration will be expensive, but, by paying for much of 
the cost of carbon capture in the price of its products, 
leading primarily carbon dioxide compression and sequestration 
costs to be incentivized, industrial gasification can provide 
the lowest cost and quickest route to for incentivizing and 
implementing such commercial demonstrations.
    Thank you for the opportunity to share Eastman's views on 
the opportunities and challenges associated with industrial 
gasification.
    [The prepared statement of Mr. Denton follows:]

  Prepared Statement of David Denton, Director, Business Development, 
          Eastman Gasification Services Company, Kingsport, TN
    Mr. Chairman, members of the committee, I am David Denton, Business 
Development Director for Eastman Gasification Services Company, a 
wholly-owned subsidiary of Eastman Chemical Company. I am a chemical 
engineer and registered professional engineer. I am a Technology Fellow 
within Eastman. In my present position, I identify and develop 
customers and project opportunities for Eastman's gasification 
business, and coordinate with public policy and technology initiatives. 
Over my 32 years experience with Eastman Chemical Company I have worked 
in a number of technical and management positions within Eastman's 
Research and Technology organizations.
                        introduction to eastman
    Eastman Chemical Company manufactures and markets chemicals, fibers 
and plastics worldwide. It provides key differentiated coatings, and 
adhesives and specialty products; is the world's largest producer of 
PET polymers for packaging; and is a major supplier of cellulose 
acetate fibers. Founded in 1920 and headquartered in Kingsport, 
Tennessee, Eastman is a FORTUNE 500 company with 2006 sales of $7.5 
billion and approximately 11,000 employees. Approximately 7,000 of 
those are employed in Senator Corker's state and another 2,600 are 
located elsewhere in the United States. For more information about 
Eastman, and its products, visit www.eastman.com.
                        eastman and gasification
    Eastman was a pioneer in commercializing the first U.S. chemicals 
from coal facility in 1983. Eastman received Chemical Engineering 
magazine's Kirkpatrick Award for Engineering Excellence for recognition 
of its ``chemicals from coal'' facility in Kingsport, Tennessee, and 
the facility has been designated an American Chemical Society National 
Historic Chemical Landmark.
    Eastman's coal gasification operating performance is industry-
leading and is highly regarded world wide. The first full year of 
operation (1984), Eastman's forced outage rate was between 8% and 9% 
and has averaged less than 2% ever since. Forced outage rate for the 
past full three year maintenance cycle was 1.06%, and the gasification 
facility was on-stream over 98% of the time.
    Eastman has a strong commitment to process improvement and has 
continually improved and optimized its gasification operations over 
time. Today, Eastman operates its coal gasifiers at the highest syngas 
output per unit gasifier volume of any GE Energy designed solids-fed 
gasifier in the world. In addition, Eastman has built a tremendous 
support infrastructure for gasification during the past two decades. 
Some examples of that support infrastructure include:

   A large data base of equipment reliability data and root 
        cause failure analyses
   Gasification modeling and simulation
   Advanced process control systems
   Process instrumentation and analysis (including on-line 
        analyses)
   Refractory design, inspection, and installation services
   Reliability-based predictive maintenance systems
   Coal, petcoke, and slag chemistry and characterization
   Optimized standard operating procedures
   Rapid gasifier start-up and switch-over procedures
   Multiple gasifier operation and integration experience
   Specialized materials science and metallurgy
   A large code-rated machine shop for critical parts 
        fabrication and repair
   Proven environmental and safety systems and procedures

    Eastman's technical, operations, and support staff have over 600 
years of combined experience in coal gasification, an experience base 
which is unrivaled in the chemical industry. In addition to experience 
with Eastman's gasifiers, Eastman has made selective hires of 
gasification experts with broad experience at other companies and 
facilities. Eastman engineers have had direct experience with start-up, 
trouble-shooting, and/or operations at over 20 gasification facilities 
around the world, including a number of petcoke and coal-fed gasifiers.
    In addition to gasification expertise, Eastman and its subsidiaries 
have over 80 years of experience in managing large integrated 
manufacturing sites. Eastman owns and operates a number of large 
integrated plant sites in the U.S. and overseas. Eastman's largest site 
in Kingsport, Tennessee, has over 7,000 employees and manufactures 
hundreds of products.
    Eastman has also developed an extensive and respected expertise in 
the management, execution, and commissioning of major capital projects. 
In external benchmarking studies, Eastman was recognized for top 
quintile performance in overall capital cost, schedule performance, and 
overall capital effectiveness, as well as being ranked best-in-class in 
several areas.
                             opportunities
    My testimony today will focus on technology ``opportunities and 
challenges'' of gasification, particularly industrial gasification, and 
on technical and institutional issues related to the potential for 
carbon capture and geologic sequestration (CCGS).
    As we begin to talk about ``gasification,'' I want to emphasis that 
this is a very general term. Gasification is not a single technology; 
there are as many different gasifiers and gasification concepts as 
there are members of this Committee, actually more. The choice of 
gasifiers and technical systems approach for a given project depends on 
many factors, principal of which are the intended product and the 
intended feedstock.
    There are fundamental differences between gasification technology 
and systems suitable for industrial processes and gasifiers that are 
designed for Integrated Gasification Combined Cycle (IGCC) power 
generation applications. These differences have significant 
implications for total system efficiencies and for readiness to 
separate carbon from other constituents in the synthesis gas stream.
    Industrial-based gasification systems, such as Eastman Chemical 
Company's facility in Kingsport, Tennessee, are inherently designed to 
capture carbon and are more thermally efficient than stand-alone coal-
fueled IGCC power generation facilities. This is also true of existing, 
or planned, industrial polygeneration gasification facilities that co-
produce chemicals, fuels or fertilizers, in addition to electric power, 
or some other baseload product.
    Unique characteristics of industrial gasification processes that 
enable or advantage high levels of carbon capture include:

   Shift Reaction--Most industrial gasification products 
        (chemicals, fertilizers, transportation fuels, or hydrogen) 
        require the syngas (the initial gaseous product from the 
        gasifier, composed primarily of carbon monoxide and hydrogen) 
        to be ``shifted,'' or enriched in hydrogen. To ``shift'' the 
        syngas, water is reacted with carbon monoxide in the syngas to 
        create additional hydrogen and carbon dioxide. This ``shift'' 
        step is not utilized in the non-capture IGCC systems.
   Quench Gasifier--The water ``shift'' reaction is 
        accomplished with a ``quench-type'' gasifier. Hot syngas from 
        the gasifier is quenched in water, saturating the syngas with 
        water for the subsequent ``shift'' reaction. For reasons that 
        are explained below under ``Capture Required'' most industrial 
        gasification plants will be designed with gasifiers that are 
        optimized for carbon capture.
   High Pressure Efficiencies--Downstream chemical conversion 
        processes require most industrial or polygeneration 
        gasification plants to operate at high pressures, higher than 
        those typically required for stand-alone electric power 
        generation. Fortunately, this same high pressure required for 
        chemical processing also makes most carbon dioxide capture 
        technologies operate more efficiently, further enhancing the 
        synergies between industrial gasification and carbon capture 
        systems.
   Capture Required--In order to use ``shifted'' syngas for its 
        industrial purpose(s), the carbon dioxide formed must typically 
        be captured, and removed to low levels prior to any subsequent 
        chemical conversion of the syngas. (To the contrary, in the 
        IGCC case presented in the MIT study The Future of Coal, carbon 
        capture is a parasitic cost and is undesirable absent a 
        regulatory requirement.) Most residual carbon in the 
        industrial-use syngas is destined for ultimate chemical 
        conversion and is thus incorporated (or sequestered) into the 
        final desired industrial product, rather than vented. A few 
        examples of durable industrial products made from chemicals in 
        which carbon is routinely sequestered include plastic handles 
        on screwdrivers and toothbrushes, tape, and automobile paint, 
        among many others. (Note: the carbon capture rate is normally 
        zero for IGCC, but can be 90+% if so designed, or added later). 
        Industrial gasification capture rates can vary widely based on 
        products, and split of products/coproducts. Typically, 
        industrial gasification projects would initially capture 50-90% 
        of feedstock carbon as CO2 or final products, but 
        can be expanded to 90+% relatively easily compared to a stand-
        alone IGCC.
   Thermal Efficiency--Industrial polygeneration has the 
        additional advantage of inherently greater thermal efficiency 
        than IGCC systems. Thermal efficiencies can vary widely, but 
        would typically be 40% for stand-alone IGCC, and 50-75% for 
        industrial gasification.

    These differences are indicated in the two illustrations that 
appear in the Appendix (pp. 7-8).*
---------------------------------------------------------------------------
    * The appendix has been retained in committee files.
---------------------------------------------------------------------------
    In addition to these technology distinctions, much of America's 
chemical industry infrastructure is located in or near geographic 
regions where carbon sequestration may present a win-win opportunity 
with enhanced oil recovery.
    So, Industrial Gasification systems present opportunities with 
respect to carbon capture and geologic sequestration. At the risk of 
using an overworked phrase, Industrial Gasification represents the 
``low hanging fruit'' as the Congress and the Administration consider a 
program to test and develop CCGS technologies, protocols regulations 
and financing issues in a commercial setting as Drs. Deutch and Moniz 
of MIT recommended to the Committee on March 22nd.
    Industrial gasification opportunities represent the logical 
economic and technological path forward to achieve four policy 
objectives that I believe are key to America's economic and 
environmental health. Those are:

          1. cost-effective environmental protection;
          2. energy security through reliance on domestic fuel 
        resources;
          3. reduction of natural gas prices and price volatility to 
        all consumers; and
          4. global competitiveness and millions of high technology 
        jobs in America's industrial sector.
                               challenges
    As promising as Industrial Gasification is for the policy 
objectives noted above, deployment of commercial gasification plants 
will not occur and the ``proving ground'' for CCGS will not be 
available unless federal and state governments provide the necessary 
incentives and framework to attract ``first adopter'' projects.
    Contrary to arguments made in the MIT study The Future of Coal, 
gasification technology is not ``commercial'' today. We at Eastman have 
the country's most experienced and successful practitioners of 
industrial gasification. But our experience of more than 20 years at 
Kingsport is, by itself, inadequate to persuade A&E firms and 
financiers to reduce the risk premiums they are currently charging for 
first-of-a-kind gasification projects in the U.S. This premium is 
currently about twenty percent higher than the cost of such plants is 
expected to be after the first dozen or so are successfully deployed 
and operated in commercial service.
    Incentives, such as Section 48A and 48B tax credits, are necessary 
to encourage commercialization of gasification projects. The use of 
gasification will cause the substitution of coal, petcoke and other 
materials for natural gas, thus resulting in decreases in demand (and 
presumably prices) for natural gas. The benefits to all Americans from 
lower and stable natural gas prices will pay for the expense of the 
Section 48A & B tax credit programs in short order. The other benefits 
previously noted make these tax programs even more compelling. However, 
none of these benefits accrue directly to the first adopters of 
gasification technology. In fact, first adopters of industrial 
gasification technology, operating in a globally competitive market, 
would be taking on more cost and risk than their competitors absent the 
Section 48B incentives. Financiers will be more likely to lend money to 
such ventures if there are external incentives to ``buy down'' the risk 
and cost for a novel project.
    As the MIT study correctly points out, in Eastman's view, the same 
incentives should apply to carbon capture and geologic sequestration. 
With the exception of conventional EOR projects, where sequestration 
may or may not occur, there is no practical reason why a company would 
spend hundreds of millions of dollars to separate, transport and store 
carbon underground. However, doing so now could have significant 
informative benefits for the entire nation if carbon management is a 
policy objective in the future.
    Federal incentives necessary to stimulate experience in carbon 
capture and long-term geologic sequestration and the subsequent 
development of protocols will be expensive. Twelve projects, based on 
different technologies and geologic circumstances will likely cost up 
to $10 billion just for the carbon capture, transportation and storage 
aspects of the projects. Incentives for gasification technology 
deployment would be a few billion additional dollars. However, the cost 
of imposing greenhouse gas reduction regulations in the future without 
a program of technology development and commercial scale deployment 
would certainly lead to inefficient choices, much greater expense to 
the country and serious loss of productivity for our economy.
    Thank you for the opportunity to share Eastman's views on the 
opportunities and challenges associated with Industrial Gasification.

    The Chairman. Thank you very much.
    Dr. Ratafia-Brown, you go right ahead.

STATEMENT OF JAY RATAFIA-BROWN, SENIOR ENGINEER AND SUPERVISOR, 
            SAIC--ENERGY SOLUTIONS GROUP, McLEAN, VA

    Mr. Ratafia-Brown. Good morning, Mr. Chairman, Senator 
Domenici, and members of the committee. Thanks so much for the 
opportunity to appear this morning to discuss the technical 
feasibility of co-converting coal and biomass to clean 
transportation fuels via gasification technology. My testimony 
is based on over 30 years of broad experience conducting 
technical and environmental analysis of energy conversion 
methods, including recent project work that specifically 
focuses on combining biomass with coal in a so-called coal-
biomass-to-liquids, or CBTL, facility.
    Co-gasification of combined coal and biomass feedstock is 
being advocated as a potential means of producing substantial 
quantities of clean diesel fuel while yielding very low levels 
of pollutant discharges, including carbon dioxide. To both 
rapidly and cost-effectively achieve these goals, this concept 
needs to utilize the technological strengths of large-scale 
coal gasification technology, which enables co-conversion to 
produce a clean syngas at the high-pressure and-temperature 
conditions required for further processing into fuels and 
capturing carbon dioxide for sequestration.
    Since the addition of biomass into a coal-based conversion 
system introduces unique technical challenges, the goal of my 
testimony is to convey that there is great promise for the 
successful engineering of such a hybrid energy conversion 
system.
    Key roadblocks to future coal and biomass conversion are 
associated with the environmental consequences of increasing 
coal consumption, the relatively small scale and high specific 
cost of available biomass-only conversion systems, availability 
and handling of sufficient biomass feedstock for an economic 
biomass-only plant size, and shutoff risk or curtailment of 
operations if there is a biomass supply shortage or supply 
reduction.
    A very promising approach to the resolution of many of 
these roadblocks is to combine conversion of coal and biomass 
within a single large facility that incorporates gasification 
technology to convert solid feedstock to syngas, syngas 
processing to remove contaminants, Fischer-Tropsch synthesis 
technology to convert syngas to clean fuel, and carbon capture 
and storage technologies for efficient and safe sequestration 
of CO2. Individual plants would have to be very 
large to capture required economies of scale: for the 
transportation sector, 25,000 to 50,000 barrels per day; in the 
chemical sector, 5,000 barrels-per-day equivalent.
    The gasifier represents the most critical component that 
impacts system design and operation. Fortunately, joint 
industry and DOE R&D efforts over the past 25 years have 
developed large-scale entrained flow gasification, which 
demonstrates the design and operational characteristics needed 
to effectively co-gasify coal with a variety of biomass types. 
Recent commercial-scale tests have validated the efficacy of 
co-gasification in such gasifiers located at the 250-megawatt 
Polk power plant in Florida and a similar one operating in the 
Netherlands. They were able to successfully process up to 30 
percent biomass by weight, or 17 percent on an energy input 
basis.
    My work is primarily focused on crop-based biomass, 
particularly switchgrass and short-rotation woody crops, such 
as poplar and eucalyptus. Unfortunately, their overall energy 
density--energy content per unit volume--is only about 10 
percent that of coal. As a consequence, biomass requirements 
with regard to transport, storage, and handling are very high 
in comparison to heat contribution to the plant. Therefore, 
densification is required to mitigate such handling issues. In 
this regard, a number of relatively small-scale methods have 
been developed that are applicable. Pelletization, 
torrefaction, and pyrolysis are methods that can increase 
energy density from 5 to 20 times, but we really need larger-
scale capabilities than currently available.
    The CBTL concept also requires strict limits on various 
contaminants in the syngas, most of which come from coal, but 
biomass co-contributes elements such as calcium, phosphorous, 
chlorine, sodium, and potassium. Parts-per-billion limits are 
intended to prevent poisoning of catalysts and fouling and 
corrosion of heat exchangers and gas turbine blades. 
Fortunately, we have gained much experience with commercial 
IGCC power plants, and refinery and chemical gasifiers, and 
have established that syngas limits can be met with 
conservative system design.
    Finally, while operation of a CBTL facility can reduce 
CO2 emissions relative to more conventional coal-to-
liquids design, integration of capture/sequestration technology 
will reduce the GHG footprint to a much greater extent. 
Fortunately, high pressure entrained flow gasification lends 
itself well to integrated CO2 capture, yet the 
actual sequestration of CO2 is not yet commercially 
available, and it is vital to validate it for use with the CBTL 
technology.
    In summary, this country has spent much time and money 
developing the kind of gasification and related technologies 
that can effectively be used for coal and biomass co-
conversion. Although added R&D and longer-term tests are needed 
to better understand how to optimize CBTL, I strongly believe 
that it has great potential to improve our energy security 
while also being a good steward of the environment.
    I thank you for your kind attention.
    [The prepared statement of Dr. Ratafia-Brown follows:]

     Prepared Statement of Jay Ratafia-Brown, Senior Engineer and 
 Supervisor, Science Applications International Corporation, McLean, VA
    Good Morning Mr. Chairman, Senator Domenici and Members of the 
Committee. Thank you for the opportunity to appear this morning to 
discuss the technical feasibility of co-converting coal and biomass to 
gaseous and liquid fuels via gasification and Fischer-Tropsch synthesis 
technologies. My testimony is based on over 30 years of broad 
experience conducting technical and environmental assessment and 
systems analysis for large-scale energy conversion methods, including 
recent project work.
    Co-gasification of combined `coal + biomass' feedstock is being 
advocated by researchers as a potential means of producing significant 
quantities of transportation fuels while yielding very low levels of 
pollutant discharges, as well reduced or near-zero release of carbon 
dioxide (CO2), a greenhouse gas (GHG) forcing agent. To 
achieve these goals both rapidly and cost-effectively, this concept 
likely needs to utilize the technological strengths of large-scale, 
commercial coal gasification technology, which enables co-conversion of 
renewable crop-based biomass feedstock with coal, generation of 
suitably ``clean'' syngas at required pressure/temperature conditions, 
and the capability to efficiently capture carbon dioxide 
(CO2) for sequestration. Since the addition of biomass into 
a coal-based conversion system introduces unique technical requirements 
and challenges, my goal in this testimony is to discuss the potential 
for successfully engineering of such a hybrid energy conversion system.
               drivers for `biomass + coal' co-conversion
    The primary motivation for converting our substantial domestic coal 
and biomass resources to transportation fuels and chemicals is to 
displace the use of imported oil and, thereby, help mitigate its high 
price and supply security concerns. Inclusion of biomass in this 
endeavor also represents a potential means of reducing the 
environmental footprint of this transformation on a sustainable basis. 
In this regard, ambitious national and international goals, like the 
U.S. Biomass Research and Development Act of 2000 and the Biofuel 
Directive of the European Union, call for large biomass-based energy 
conversion capacity in order to diversify the resource base for 
transportation fuels, chemicals, and power/heat generation. The U.S. 
Vision recommends that biomass supply 5% of the nation's power, 20% of 
its transportation fuels, and 25% of its chemicals by 2030. The EU 
Vision (as of March 2007) sets a goal of 10% biofuels use for 
transportation by 2020.
    Key roadblocks to this resource conversion are associated with: 1) 
environmental consequences of greatly increasing coal consumption, 
particularly related to amplified release of greenhouse gas emissions 
(GHG); 2) small-scale, high specific-cost and relatively poor 
performance of available biomass conversion technologies; 3) 
availability of sufficient biomass feedstock (locally) for an economic 
plant size; and 4) shut-off risk or curtailment of operations if there 
is a biomass supply shortage or reduction in supply.
    A very promising approach to resolution of most of these roadblocks 
is to combine conversion of coal and biomass in a large-scale facility 
that incorporates gasification technology to convert solid feedstock to 
syngas (primarily H2, CO, CO2, H2O, 
and CH4); syngas processing to remove unwanted contaminants 
such as sulfur, potassium, and mercury; Fischer-Tropsch (F-T) synthesis 
technology to convert syngas to clean liquid fuels (naphtha and 
diesel); carbon capture and storage (CCS) technologies technology to 
allow efficient and safe sequestration of CO2; and power 
generation technology to both supply internal requirements and 
electricity for sale. Individual plants would have to be very large to 
capture required economies-of-scale: Transportation Sector--25,000 to 
50,000 barrels/day; and Chemical Sector--5,000 barrels/day equivalent. 
I will refer to this as the coal/biomass-to-liquids (CBTL) concept.
    The environmental consequences of this approach, particularly as 
related to the net release of CO2, have been investigated by 
researchers from the Princeton Environmental Institute.\1\ Their 
findings indicate that a plant that combines co-gasification of biomass 
(switchgrass) and coal could potentially achieve a near-zero net 
CO2 emission rate by exploiting the negative emissions of 
storing photosynthetic CO2 in roots and soils. By 
comparison, the CO2 emission rate for coal-only F-T liquids 
production, with CCS, could be reduced to about the same rate as crude 
oil-derived fuels. This approach could also require considerably less 
net biomass input to realize near-zero emissions than conventional 
biofuels conversion, such as cellulosic ethanol.
---------------------------------------------------------------------------
    \1\ Williams, R., ``Synthetic Liquid Fuels From Coal + Biomass with 
Near-Zero GHG Emissions,'' Princeton Environmental Institute, Princeton 
University, January 12, 2005.
---------------------------------------------------------------------------
    Let me summarize the key drivers for CBTL concept as I see them: 1) 
Reduction of imported crude oil; 2) Continued use of our abundant coal 
resources in an environmentally acceptable manner; 3) Greater 
utilization of our abundant biomass resources in accordance with our 
national goals; 4) Efficient and cost-effective utilization of biomass 
resources; 5) Coal acts as a ``flywheel'' to keep a facility operating 
even if biomass is not sufficiently available; 6) Within a strict 
carbon-constrained framework, such as McCain-Lieberman, this approach 
should become cost-effective, 7) Use of reliable coal in concert with 
more environmentally acceptable renewable feedstock may reduce project 
financial risk for large-scale energy conversion plants; and 8) 
Gasification-based projects could benefit significantly from the more 
positive public attitude displayed towards co-utilization of renewable 
feedstock, as well as development of a reliable multi-source fuel 
supply network for such projects.
    Successful technical and cost-effective implementation of CBTL 
particularly depends on adoption of suitable gasification technology, 
addressing biomass handling challenges, satisfying syngas ``cleanup'' 
constraints, and effectively integrating CCS. My intent in the 
remainder of this testimony is to focus on the challenges that each 
represent and their potential for enabling this concept to function 
effectively.
           gasification technology capability and experience
    First, I want to convey that gasification technology is in 
widespread use today. The 2004 World Gasification Survey, sponsored by 
DOE, shows that in 2004 existing world gasification capacity had grown 
to 45,000 MWth of syngas output at 117 operating plants with a total of 
385 gasifiers. Coal (49% of capacity), petroleum products (37%) and 
natural gas (9%) currently dominate the gasification market as the 
primary feedstocks for production of F-T liquids, chemicals, and power. 
Note, however, that biomass gasification only accounts for about 2% of 
the total syngas production. Exhibit 1* presents a summary of large-
scale gasification experience.
---------------------------------------------------------------------------
    * All exhibits have been retained in committee files.
---------------------------------------------------------------------------
    The gasification technology represents the most critical component 
that impacts system design and operation of a CBTL facility. The 
desirable design characteristics for co-gasification technology for F-T 
liquids applications (using high rank coals) are: large individual 
gasifier throughput (>1000 MWth); high temperature (>2,300 F to 
eliminate tars/oil contaminants in the syngas); high pressure to 
increase syngas throughput and reduce process component sizes; oxygen-
blown (as opposed to air-blown) to eliminate nitrogen as a syngas 
diluent; slagging (a consequence of high temperature operation) to 
render most of the feedstock ash as a benign byproduct for utilization 
purposes; dry feed of biomass since it is difficult to handle as a 
slurry, and use of a relatively large particle size to reduce feedstock 
preparation.
    Fortunately, these design characteristics are generally met with 
the widely used entrained-flow gasification technology, which currently 
dominates the large-scale gasification market with 85% of the installed 
units. (Note that this technology also continues to benefit from a 
variety of related R&D efforts sponsored by DOE to further improve 
performance and cost, including development of a compact transport-type 
gasifier technology.) While these gasifiers are quite flexible with 
regard to feedstock characteristics, their high reaction rates demand 
very small feedstock input size (e.g., <100 micron or 0.004 inches) 
that is easily achievable for friable materials like coal, but more 
challenging and energy-consuming for biomass feedstock. Compounding 
this important issue is the high pressure injection requirement for the 
entrained-flow technology, which may present a challenge to biomass 
injection into the gasifier. Also, the chemical make-up of biomass ash 
will cause it to behave differently that coal ash, which must be 
accounted for in design and operation. Several large-scale 
demonstrations of entrained-flow co-gasification of coal and biomass 
have already been performed here and in Europe.
    Commercial scale co-gasification of biomass with coal has been 
demonstrated at the 253 MWe Nuon IGCC power plant in Buggenum, The 
Netherlands (using the dry-feed Shell entrained-flow technology), as 
well as at Tampa Electric's 250 MWe Polk IGCC power plant (using GE 
entrained-flow technology). (The latter was built in the 1990s as part 
DOE's Clean Coal Demonstration Program.) The Nuon plant recently tested 
biomass content up to 30% by weight (17% of total energy input), which 
requires up to 205,000 tons/year of biomass feedstock and coal feed is 
about 435,000 tons/year. Besides gasification of demolition wood, tests 
were also conducted with chicken litter and sewage sludge. The co-
gasification tests conducted at the Polk plant used up to 1.5% by 
weight of woody biomass harvested from a 5-year-old, locally-grown 
Eucalyptus grove. Since the plant uses 2,200 tons/day of coal, the 
biomass co-gasification basis was 33 tons/day (about 10,000 tons/yr).
    Not only did these plants operate normally, but we can generally 
conclude that biomass feed size can be on the order of 1 mm (0.04 
inches) due to biomass' high reactivity relative to coal. The 
importance of this lies in the capability to minimize biomass milling 
power consumption and possibly avoid other efficiency-reducing pre-
treatment processes. The Nuon experience has also shown that a 
relatively high throughput of biomass is possible in an entrained-flow 
unit that is co-gasifying coal. Pilot-scale tests were also tests were 
also conducted at the National Energy Technology Laboratory (NETL)/
Morgantown some years ago with coal and up to 35% biomass.
                coal + biomas co-gasification challenges
    Below, I provide a brief overview on key challenges associated with 
oxygen-blown, entrained-flow gasification of coal and biomass.
    Oxygen feed to the gasifier--standard cryogenic method of oxygen 
production is both costly and energy intensive; however, DOE is well 
into development of so-called ion transport membrane (ITM) technology, 
which promises significant cost reductions and efficiency gains.
    Biomass and coal injection--Feedstock injection into high pressure 
gasifiers is challenging. Conventional dry-feed methods employ a series 
of complex lock hoppers. Due to the low energy density of biomass, lock 
hoppers have two major disadvantages: (1) large amounts of inert gas 
are required and must be compressed, and (2) gasification efficiencies 
drop due to the dilution of the syngas. Fortunately, DOE's gasification 
program has been developing a rotary dry-feed coal pump that, when 
fully tested, should allow the feedstock to be ``pushed'' directly into 
the gasifier.
    Biomass particle size--While entrained-flow gasifiers require very 
small coal particle sizes (<0.004 inches), recent commercial `coal + 
biomass' tests suggest a much larger size (0.04 inches) is likely 
feasible due to the high reactivity of biomass due to its high 
O2 and volatiles content
    Biomass ash slagging behavior--While the slagging performance of 
the biomass ash may be an issue, testing has shown that ``flux'' 
material (aluminum-silicates) can be added to the gasifier to re-
establish acceptable ash slagging performance.
    The bottom-line is that the practical limit of biomass co-
processing with high rank coals (bituminous and subbituminous coals) is 
probably associated more with biomass preparation and feed issues and 
desired syngas production level, than the capabilities of the 
entrained-flow gasification process.
                      biomass handling challenges
    Our work has primarily focused on crop-based biomass, particularly 
prairie grass/switchgrass and short rotation woody crops (SRWC), such 
as Poplar and Eucalyptus. These are defined as fast-growing, 
genetically improved trees and grasses grown under sustainable 
conditions for harvest at 1 to 10 years of age. In general, their 
biomass heating values [MJ/kg] and particle densities are about half of 
that of coal, whereas bulk raw densities [kg/m3] are about 
20% of that of coal, resulting in overall biomass energy density [MJ/
m3] approximately 10% of coal (see Exhibit 2). As a 
consequence, when co-gasifying raw biomass at a 10% heat input rate 
with coal, the volume of coal and biomass can actually be similar; 
therefore, biomass requirements with regard to transport, storage and 
handling are very high in comparison to its heat contribution.
    Biomass either has to be located very close to a conversion 
facility and processed immediately, or some form of ``densification'' 
needs to be implemented to mitigate handling issues. Since this is a 
well-recognized issue for biomass, especially for conversion processes 
that can consume very large quantities, a number of methods have been 
developed, albeit currently at small-scale, that are applicable. These 
are pelletization, which is a drying/compression method that increases 
energy density of switchgrass pellets by a factor of eight. 
Torrefaction is a ``roasting'' treatment that operates within a 
temperature range of 200 to 300 C and is carried out under atmospheric 
conditions in the absence of oxygen. This process not only increases 
the energy density of wood by about 25%, but also greatly reduces the 
milling energy consumption to reduce size. Combined torrefaction and 
pelletization can increase the energy density of wood by about five 
times. Pyrolysis is an option to produce a liquid product (pyrolysis 
oil) from biomass, via its thermal decomposition, at temperatures of 
450-550 C. Yield efficiency of pyrolysis oil production averages about 
70%, and volumetric energy content of pyrolysis oil is 19 68,300 Btu/
gal compared with No. 6 Oil at 144,000 Btu/gal.
                     syngas ``cleanup'' constraints
    The CBTL concept requires strict limits on various contaminants in 
the syngas, most of which come from coal, but biomass co-contributes 
certain elements and related compounds such as calcium (Ca), 
phosphorous (P), chlorine (Cl), sodium (Na) and potassium (K). The 
limits are intended to prevent poisoning of the F-T catalysts and 
fouling/corrosion of downstream system components, such as heat 
exchangers and gas turbine blades. As an example, constraints on alkali 
metals (Na + K) are less than 10 part per billion by volume (ppbv) and 
halides (HCL + HBr + HF) are also less than 10 ppbv. These and other 
limits are controlled via the integration of a group of processes that 
sequentially treat the syngas once it exits the gasifier. These include 
dry particulate removal, wet syngas scrubbing for fine particulate and 
gases, mercury removal, and acid gas (H2S and 
CO2) removal. Experience with commercial IGCC power plants, 
such as the Polk IGCC plant and the Wabash River plant (another DOE 
Clean Coal Technology Program investment), as well as refinery 
gasifiers, have established that the CBTL syngas limits can be met with 
appropriate system design.
                  carbon capture and storage challenge
    Operation of a CBTL facility will reduce CO2 emissions 
relative to a more conventional coal-to-liquids (CTL) design, even 
without integration of CCS technology. The extent of the reduction 
depends on the relative level of biomass energy input. For example, the 
30% (by weight) biomass feed to the Nuon plant that I discussed 
previously, resulted in an effective CO2 reduction of about 
17% or 220,000 tons/yr (excluding GHG emissions related to biomass 
collection and treatment). On the other hand, integration of CCS 
technology will reduce the GHG footprint of CBTL to a much greater 
extent. However, while CO2 capture technology is 
commercially available and well-proven for gasification-type 
applications, it increases capital expenditure and operating costs; DOE 
is currently developing advanced membrane technologies to lower this 
impact. More importantly, the actual sequestration of CO2 is 
far from commercially available and acceptable. As stated by DOE, key 
challenges are to demonstrate the ability to store CO2 in 
underground geologic formations with long-term stability (permanence), 
to develop the ability to monitor and verify the fate of 
CO2, and to gain public and regulatory acceptance. DOE's 
seven Regional Carbon Sequestration Partnerships are engaged in an 
effort to develop and validate CCS technology in different geologies 
across the Nation. This is vital to sequestration's future and use with 
the CBTL technology.
                               conclusion
    Even without considering currently favorable government programs to 
encourage investment in CTL and CBTL technology, I've endeavored to 
convey that that there are considerable drivers that strongly support 
continued development. Importantly, it takes advantage of the 
significant investment and progress that the country has made with 
gasification and related technologies over the past twenty-five years. 
Commercial entrained-flow gasification technology has been proven to be 
capable of co-gasifying coal and biomass, which at the minimum would 
permit reduced GHG emissions from future CTL facilities. Incorporation 
of CCS technology, when sequestration is technically available and 
appropriate to regulatory conditions, can have a major impact on the 
sustained use of our abundant coal resources and greater use of our 
biomass resources. Although, I've reported on some successful tests of 
coal and biomass co-gasification, I've also attempted to convey that 
R&D is needed to deal with significant challenges related to biomass 
handling and feeding issues that are important to plant operability and 
cost-effectiveness. Also, longer-term, large-scale tests of the CBTL 
concept are required to better understand how a well-integrated design 
will perform and function. Overall, I strongly believe this is a 
technology that has great potential to improve our energy security 
while also being a good steward of the environment.
    I will be happy to answer any questions.

    The Chairman. I thank you very much. Thank you all for your 
good testimony.
    Let me start. And we'll do 5-minute rounds here.
    I'll start with a question to Mr. Fulkerson. The idea you 
presented, which you attributed to Bob Williams at Princeton, 
was presented last month when you had your group together, your 
research and development group, folks from the National 
Laboratories, as I understand it. Could you be a little more 
explicit about what is the extent of the capture and 
sequestration that would be required as part of this? I mean, 
if this combined biocoal effort is adopted, or this technology 
is adopted, would there also have to be an attendant capture 
and sequestration effort made in order for it to meet the 
environmental standards that you think are appropriate?
    Mr. Fulkerson. Yeah, of course. As Jay has just pointed 
out, the biomass coal gasification process has to be 
accompanied by sequestration of all of the CO2 that 
is excess in the process. But the interesting point is that the 
biomass carbon which is sequestered is a net-negative, and, 
therefore, it offsets the carbon that is emitted subsequently 
by burning the product fuel, so that the overall well-to-wheel 
kind of climate impact can be net-zero. That's----
    The Chairman. OK.
    Mr. Fulkerson [continuing]. The important point of it.
    The Chairman. ``Net-zero,'' meaning that there would be no 
requirement for a separate carbon capture and sequestration 
effort as part of this. Is that what you mean by ``net-zero''?
    Mr. Fulkerson. Yes. What I mean is the overall process, 
including burning the product fuel----
    The Chairman. Right.
    Mr. Fulkerson [continuing]. Produces net-zero carbon 
emissions. In other words, most of the of the carbon is 
sequestered, but the carbon that is sequestered includes carbon 
from biomass, which is a net-negative, since biomass, in being 
grown, absorbs CO2 from the air.
    The Chairman. Right.
    Mr. Fulkerson. So, that's got----
    The Chairman. So, you're saying that, by sequestering the 
carbon, you then are net-positive, and then, when you burn the 
fuel, you use up your net-positive, and you come out----
    Mr. Fulkerson. Right.
    The Chairman [continuing]. At zero.
    Mr. Fulkerson. Right. Right.
    The Chairman. OK.
    Mr. Fulkerson. I said----
    The Chairman. Let me ask Dr. Herzog if you agree with that 
analysis, that this would be where you wind up in the process.
    Ms. Herzog. Yes, I do agree with the analysis, but let me 
make a slight distinction.
    The biomass is good. If you just used biomass, you'd be 
net-negative. Including the coal, thus, brings you back up. You 
could get net-zero, but that means using a lot of biomass in 
this system. The question, I think, is, ``Is that the best use 
of all this biomass, with the goals in mind that we have, which 
is to reduce our oil dependence and reduce our global warming 
emissions?'' That's what needs to be assessed properly.
    The Chairman. Mr. Fulkerson, you seemed to disagree with 
some of that.
    Mr. Fulkerson. Dr. Herzog, let me add to what you said.
    The beauty of biomass and coal together is that the amount 
of biomass that you have to use per unit of product fuel is 
much less than you would have to use if you went the cellulosic 
ethanol route. That's the interesting trick of this. That's 
the, ``Why is that?'' It's because the coal supplies most of 
the energy to run the process. That's the reason you get a much 
smaller requirement of biomass to come up with this zero-net 
carbon emissions----
    The Chairman. I'm about to run out of my time here, but let 
me just nail down the stage this idea is in. This was presented 
to you last month in your R&D group. Are there examples of this 
functioning? Are there demonstration projects that are using 
this technology? Where are we? I mean, are we looking at doing 
this 2 years from now, 5 years from now, 10 years from now, on 
a commercial scale?
    Mr. Fulkerson. Yes, I would say that Dr. Ratafia-Brown's 
testimony gave you where the state-of-the-art is. As I 
understand it, there's up to 10 or 15 percent biomass with coal 
in gasification in the Netherlands, so these things are coming 
along. There is no inherent reason why they shouldn't work, 
except the kind of details that Jay pointed out, which are a 
lot of details of things have to be ironed out for this. His 
testimony provided us closer to the state-of-the-art, as well 
as Jim Bartis, here.
    The Chairman. OK. All right. Well, I don't want to overstay 
my time. Let me go ahead and call on Senator Domenici.
    Senator Domenici. Chairman, you're welcome--if he wants 
more time, go ahead.
    The Chairman. Well, let me just ask one question of Dr. 
Ratafia-Brown.
    You say in here--I think he's referring to page 5 of your 
testimony, where you talk about this plant in Belgium--or in 
the Netherlands, excuse me.
    Mr. Ratafia-Brown. That's correct.
    The Chairman. Yes. Could you tell us what the status of 
that is? I mean, if this is such a great technology, and the 
Dutch have been doing this for some period of time here, I 
guess----
    Mr. Ratafia-Brown. Well, the reason that came about, 
Senator, is because the Dutch have a mandate for this plant to 
reduce their CO2 contribution to the Dutch 
inventory, and they placed--I believe it was a 200,000 ton-per-
year reduction of CO2 on this facility. They 
fought--therefore, back in 2001, to co-gasify chicken litter 
and wood waste and some other biomass, up to, I believe, in 
2004, it was 30 percent by weight, which was about 17 percent 
on an energy-input basis to the plant. They've successfully 
done this. They've had some technical issues, but I think the 
overall experience is quite good. Therefore, their 
CO2 reduction has come strictly from the co-
gasification of biomass.
    The Chairman. You're suggesting that we could do something 
similar in our coal plants?
    Mr. Ratafia-Brown. We have two plants in this country that 
operate very similar to that. It's the Polk Plant in Florida 
and the Wabash River Plant in Indiana. They both operate 
integrated gasification combined-cycle plants. The Polk Plant 
also has tested biomass at their facility very successfully 
back in--I think it was----
    The Chairman. Very successfully as a way to reduce the 
emission?
    Mr. Ratafia-Brown. It was just a test to see if they could 
process it and reduce emissions, that's correct.
    The Chairman. OK. All right, thank you.
    Senator Domenici.
    Mr. Ratafia-Brown. You're welcome.
    Senator Domenici. Mr. Bartis, to follow your middle-of-the-
road--what specific steps would the Congress have to put in 
place? If we take those steps, what is the likelihood of 
success? Please give us this list, again, now.
    Mr. Bartis. Well, the first step is to resolve the 
uncertainty associated with what these fuels really cost.
    Senator Domenici. All right, so----
    Mr. Bartis. We just don't have a handle on that. It's not 
very expensive. We could cost-share, with private industry, the 
development. But there are no funds allocated to this right 
now. But if we could get the front-end engineering design, then 
we would know what these plants cost. Truly know.
    Now, let me put this in perspective. These plants run 
billions of dollars. The detailed engineering package for a 
plant like this would be a couple--100 million, $200 million to 
get the blueprints. Before you go to that step, you go and get 
a front-end engineering design. That costs about $30 million. I 
believe that it's possible that, if the Federal Government came 
in with a 50-50 cost share, we could get extremely valuable 
information on what these plants truly cost. Right now, we're 
dealing with very low-level design work primarily done for R&D 
purposes, not for investment quality. The second step----
    Senator Domenici. There would be no reason for you to think 
that this kind of investment would produce the kind of 
technology application and reality of----
    Mr. Bartis. Well, our view--we've spoken with a large 
number of firms--is that without an incentive package, you're 
not going to get the participation of the private sector here. 
So, unless it's through a broadbased tax or through specific 
incentives--and we've looked at these incentives--we're not 
going to make progress here. There's just too much uncertainty 
on world oil prices.
    Senator Domenici. OK. Now, in your opinion, if you did have 
the incentives, is the technology apt to produce a feasible 
plant----
    Mr. Bartis. Yes.
    Senator Domenici [continuing]. That will do the job?
    Mr. Bartis. Yes. We have options right now for the initial 
set of plants for carbon management. There's no reason that any 
of these plants should exceed what's typical when we use oil in 
refining. So, the first set of plants can certainly come out--
what I'll call carbon-neutral, in the sense that they're no 
worse with regard to emissions than the oil that they're going 
to displace.
    Senator Domenici. All right.
    Mr. Bartis. And we have those applications here and now. 
And in the future we've got a great chance to go to what Mr. 
Fulkerson described as zero emissions, as good as you can get.
    Senator Domenici. All right. Now, let me ask--if we did 
this, is it possible that the best incentive might be for us to 
do this on a plant-by-plant basis to get it started, by saying 
we'll take three of them, let's say, or four, and we will say--
we've got this agreement, and the price will come out all 
right, because the American Government will buy the stream at a 
price that is assured?
    Mr. Bartis. We have looked at that option, and our analysis 
says that a purchase commitment may not be in the best interest 
of the taxpayer, that there----
    Senator Domenici. OK.
    Mr. Bartis [continuing]. Are better options in which risks 
can be shared better. Those options--if you'd like, I can 
summarize.
    Senator Domenici. Sure.
    Mr. Bartis. The most effective option to getting the best 
of our firms involved is probably a front-end incentive, such 
as a tax credit, which improves the overall investment profile 
of such a plant.
    Now, the second important incentive is something that 
protects the investor, in case oil prices plummet. The larger 
that front-end incentive is, the lower that barrier needs.
    Finally, we believe that it's very important to look at 
cost-sharing. The companies we've talked with also see that as 
a favorable approach, some kind of collar so that there's some 
kind of recapture of the Federal risk-taking.
    We don't at all see loan guarantees as a useful tool, 
because they don't attract the right set of players here.
    Senator Domenici. OK. Let me just summarize, from my 
standpoint, with the two of you, Mr. Bill Fulkerson, speaking 
either for yourself or for your mentor, whichever you like, if 
that's what he is, and then--if you can speak for him--and 
James Bartis. Talking about this subject and wondering where we 
have something that will work--now, there may be more things 
that will work, so I'm not trying to tell our committee this is 
the only one. But you are suggesting there is a known 
technology that has had sufficient practice, albeit not with a 
large commercial plant, but that there has been sufficient 
practice with it that the two of you believe, with proper up-
front incentives that are fair, that we could, indeed, get in 
this and come out with a plant or two, whichever we choose--and 
we can have a little bit more variety, but if our goal is to 
produce a plant that is neutral, in terms of carbon emission, 
we could do that, if we want, and get it built, to show the 
world that carbon can be used for this purpose. Is that right, 
Mr. Fulkerson and Mr. Bartis? Is that what you're telling this 
Senate committee?
    Mr. Fulkerson. Well, I think what you said if you mean 
carbon-neutral as good as petroleum----
    Senator Domenici. As----
    Mr. Fulkerson [continuing]. Then, absolutely, yes. 
Absolutely yes.
    Senator Domenici. All right. Let's say it that way for the 
record.
    Mr. Fulkerson. Okay. If that's what your goal is--if your 
goal, however, is to be better than petroleum, because 
petroleum is a major emitter of carbon dioxide in the world--
then you have to incentivize, as well, other technologies, such 
as the biomass/coal combination. Now, it's not going all that 
much further to do that. So, I think that with existing 
technologies, or near existing technologies, that you could 
accomplish both, and you should. In my testimony, I gave about 
six policies that, in concert, I think, would drive us in the 
right direction without specify--with picking winners, without 
picking technological winners. In other words they're 
technology-neutral. This is one of the technologies that would 
be incentivized. Whether it's the one that would win, I don't 
know, but--anyway.
    Senator Domenici. Mr. Bartis.
    Mr. Bartis. I endorse that. We have the technology on the 
shelf today, and we can make it better than it's ever operated 
in the past by putting the right companies in charge. But it's 
on the shelf, and we can build it today. We can match the 
carbon emissions of conventional petroleum. That's the good 
news. We can solve a major national security and economic 
problem.
    The other critical component is going beyond that and, over 
the longer term, building these plants, and to get that done 
means we have to demonstrate, at multiple sites, carbon capture 
and sequestration. That is not in the current plans of the 
Department of Energy. It's critical. In fact, I believe that 
maybe two or three of these initial plants, could be used to 
generate the carbon dioxide needed for those massive 
demonstrations. But it's critical that we move forward there.
    Mr. Fulkerson. Jim, let me ask you--you said that we could 
do the existing thing today, without sequestration. That--and 
be equivalent to petroleum--that's not true. Your gasification 
liquids process will produce about twice as much of 
CO2 as petroleum. So, to even bring it neutral, you 
have to sequester the excess carbon. Isn't that right?
    Mr. Bartis. I was thinking of initial plants using it for 
enhanced oil recovery operations, or as a demonstration of 
these carbon sequestration.
    The Chairman. So, that's another way of sequestering it.
    Mr. Bartis. Another way of sequestering would be enhanced 
oil recovery.
    The Chairman. Right.
    Senator Bunning.
    Senator Bunning. My goodness, where do I start?
    Since I have a bill in, I've got to get to the coal-to-
liquids use with biomass to produce a fuel, whether it be a 
fuel that is used in trucks and/or diesel fuel. But, even more 
importantly, I've been dealing with the Air Force, and they are 
so interested in this process as a national security issue, 
where we use the same type of process, including biomass, to 
produce aviation fuel.
    Mr. Fulkerson, is that a distinct possibility, to produce 
the same type of diesel and aviation fuel by using biomass and 
coal?
    Mr. Fulkerson. Absolutely.
    Senator Bunning. And, therefore, reducing the footprint.
    Mr. Fulkerson. The only difference is the----
    Senator Bunning. It's the cost of building the plant.
    Mr. Fulkerson. Yes.
    Senator Bunning. OK. If we incentivize that and change the 
rules--we've got bad rules, as far as purchases by the Air 
Force, so we limit it to a 5-year contract, and you have to pay 
as you go each year--we've got to change the rules if we're 
going to allow the Air Force to use that fuel. So, I want to 
get this correctly through my head, because of all the 
misinformation that's out there.
    The technology now exists to produce, with coal and 
biomass, a fuel that will burn as clean as our petroleum-based 
fuels, presently. If we use the carbon capture at the plant, 
and use it for other purposes, or sell it, or we sequester it, 
we have a much better fuel than a petroleum-based fuel. 
Anybody?
    Mr. Fulkerson. Absolutely. Absolutely.
    Senator Bunning. Mr. Brown? Since you're in the business, 
and--David, you are also in the business, and you are in the 
business, Jim--go ahead.
    Mr. Bartis. Allow me to make one caveat here.
    Senator Bunning. OK.
    Mr. Bartis. All right. The use of biomass and coal is an 
extremely low-risk option. However, as Mr. Ratafia-Brown has 
mentioned, although there has been experience, it's been very 
limited experience----
    Senator Bunning. Correct. It's not----
    Mr. Bartis [continuing]. Versus.
    Senator Bunning [continuing]. Large-scale.
    Mr. Bartis. So, there may be----
    Mr. Ratafia-Brown. It had been large-scale.
    Mr. Bartis. It has been large-scale, but on only specific 
types of biomass----
    Senator Bunning. OK.
    Mr. Bartis [continuing]. I think we all agree there may be 
a need to do some large-scale testing before a company would be 
willing to put this technology on a multibillion-dollar plant. 
There may need to be some tests. I know there are test sites 
available, and this could be done----
    Senator Bunning. My time's running out. What I want to ask 
is that--similar to Senator Domenici--we know we have a big 
picture out here. If we don't put coal-to-liquids technology in 
the picture, we are limiting our options to synthetic fuels, 
whether it be just ethanol, or whether it be soybeans to 
diesel, or whatever--we're limiting our options. Therefore, 
we're still going to be dependent on Middle East oil or oil 
from somewhere. So, why not look at all the options and 
incentivize all the options so that we can get all of the 
things on the table at once?
    Would you agree or disagree? Go ahead, ma'am. Please.
    Ms. Herzog. Thank you. I'd like to take a step back and, 
again, look at what the goals are. The goals are to reduce oil, 
and also, from our perspective, reduce global warming 
emissions, and not to pick the winning technology----
    Senator Bunning. I don't want to pick them.
    Ms. Herzog [continuing]. Which is what you're saying. And 
I----
    Senator Bunning. No, but I said put them all out.
    Ms. Herzog. So, the way--we believe--to do that most 
effectively is to set the standard and let the market find the 
most promising technologies. Very possibly, it might be what 
you're suggesting, but that needs to play on an equal playing 
field with all the other opportunities out there.
    Senator Bunning. I agree. But we also have to get some kind 
of global agreement. The United States can get to zero in 
emissions. If we don't get an agreement out of China and India 
and other places to lower their emissions, we are not going to 
have an effect on global warming anywhere in the world because 
China's going to open up 94 coal-fired generation plants this 
year, with no restrictions on them.
    Ms. Herzog. But----
    Senator Bunning. So, we need to have some kind of an 
agreement, globally.
    Ms. Herzog. I absolutely agree, and we're as concerned 
about China and the rest of the world as you are, and also 
concerned about U.S. emissions.
    Senator Bunning. Thank you very much, panel.
    The Chairman. Senator Salazar.
    Senator Salazar. Thank you very much, Chairman Bingaman and 
Senator Domenici, for holding this very, very important 
hearing.
    I appreciate your knowing that many of us on this committee 
come from States that have a lot of coal, and use a lot of coal 
in powering the energy that we use. In my State, 71 percent of 
our electricity is generated from coal. We have coal mines and 
coal miners throughout the western slope of my State through 
the southern end of my State, and I recognize coal has this 
abundance that makes it a very attractive place for us to look 
at addressing the national security and environmental security 
issues of our time.
    So, the real debate, it seems to me, here in this 
committee, and probably on the Senate floor, will be how is it 
that we can move forward and develop the use of our abundant 
coal resources in a way that does not do damage to our 
environment, in a way that does not compromise our 
environmental security?
    So, I have a couple of questions. First, to you, Dr. 
Herzog. In terms of a hybrid electricity technology for 
vehicles, is there a way, through IGCC, and through moving 
forward with advanced vehicle technologies, with battery-
powered vehicles that are plugged in at night--is that the kind 
of thing that you think has some possibility for us to use some 
of our abundant coal resources?
    Ms. Herzog. Absolutely. GM is developing plug-in hybrid 
electric vehicles. So are other automobile companies. The 
exiting thing about plug-in hybrid electric vehicles, which I 
said in my testimony and remarks, is that you can use coal 
gasification, capture the carbon dioxide, create electricity to 
the plug-in hybrid electric vehicle, save much more oil, and 
reduce greenhouse gas----
    Senator Salazar. Let me ask you, then, this. What is it 
that we, as a committee that understands the volume of coal 
that we have available here in the United States of America, 
can do to further incentivize that goal----
    Ms. Herzog. Right.
    Senator Salazar [continuing]. To happen sooner than later?
    Ms. Herzog. Right. So, as I said just now, I don't believe 
in picking technologies. I think this could very possibly be 
the winner, but what we need to do is put a cap on our carbon 
emissions, headed to where we need to be in the next decades to 
come, so a declining cap that will set a market signal on 
carbon. In addition, I think standards to help promote--an 
incentive to help promote technologies, more general within a 
carbon cap, make a lot of sense. For example, a low-carbon fuel 
standard, where electricity to plug-in hybrids would qualify. 
To have that low-carbon fuel standard starting at a level, in a 
few years, and then slowly ramping down over time to make sure 
that our transportation sector emissions are heading in the 
direction they need to be heading, and not to invest in 
technologies today which won't make any sense in 10-20 years.
    Senator Salazar. Thank you, Ms. Herzog.
    Mr. Fulkerson, I think it was you that testified about the 
fact that we already have two IGCC plants that use biomass here 
in our country, one in Polk, Florida, and one in Wabash, 
Kentucky. Was that your testimony, or another witness?
    Mr. Fulkerson. Jay's testimony.
    Senator Salazar. That was Jay's testimony. Let me ask you 
both. Given two plants that have already been doing IGCC with 
biomass that deals with the greenhouse emissions issue, why 
isn't this technology being, essentially, deployed, and being 
picked up by the commercial market, at this point in time?
    Mr. Ratafia-Brown. Well----
    Senator Salazar. Jay and Bill, why don't you take a quick--
--
    Mr. Ratafia-Brown. Well, we don't currently operate within 
a climate change framework. There's no incentive for these 
plants to use a crop, that they may have to pay for, to add to 
their, you know, already plentiful fuel supplies. Now, in the 
State--in the case of the Netherlands, their country did 
mandate that that plant----
    Senator Salazar. So, for the case of the Florida and 
Kentucky plants, they just did it out of being----
    Mr. Ratafia-Brown. That was a test----
    Senator Salazar [continuing]. Good Samaritans. They just 
wanted to go and try it----
    Mr. Ratafia-Brown. It was----
    Senator Salazar [continuing]. To see how it worked.
    Mr. Ratafia-Brown [continuing]. A test to determine whether 
that gasifier can handle it, and----
    Senator Salazar. The results of those tests, you said, were 
positive?
    Mr. Ratafia-Brown. Extremely positive.
    Senator Salazar. OK. But it was just a test. They're not 
currently using it.
    Mr. Ratafia-Brown. That's correct. I do----
    Senator Salazar. OK.
    Mr. Ratafia-Brown. [continuing]. Want to point out one 
thing, if I might, with regard to these plants, these CBTL 
plants. They not only produce fuels, they do produce 
electricity for plug-in hybrids. A 50,000 barrel-per-day plant 
will also produce 125 megawatts of electricity for sale to the 
grid. So, these----
    Senator Salazar. Dr. Herzog, what's----
    Mr. Ratafia-Brown. [continuing]. This is a win-win-win.
    Senator Salazar [continuing]. What's the problem with 
moving forward with projects like the ones that have already 
demonstrated what they can do in Kentucky and Florida?
    Ms. Herzog. Well, my understanding is, the Polk Plant is a 
coal gasification plant that produces electricity. It's been 
running for quite some time. If they added biomass, it was 
only--I mean, it's not running on biomass now.
    Mr. Ratafia-Brown. No, no. That was strictly a test 
sponsored by the Department of Energy--again, to test the 
viability of it.
    Senator Salazar. Well, the tests work. Here's my question 
I'm trying to get to. We know the tests work in the 
Netherlands, we know they worked in Florida, we know it worked 
in Kentucky. The question is, ``How do we make that happen on 
more than a test basis, whether it's these two plants or 50 
plants, or whatever the number is?''
    Mr. Ratafia-Brown. Well, I think that----
    Senator Salazar. Dr. Fulkerson----
    Mr. Ratafia-Brown [continuing]. Speaks to what Jim was 
talking about.
    Senator Salazar. Dr. Fulkerson, why don't you respond?
    Mr. Fulkerson. You've got to make the economics work. The 
problem is that unless there is a carbon tax, or equivalent, 
then there's not adequate incentive to build a plant that 
sequesters carbon, for example. OK? Without that, you're not 
going to have anything happening in the private sector until 
you put that regulation in place, which I assume----
    Senator Salazar. The carbon limitations--
    Mr. Fulkerson [continuing]. That the Congress----
    Senator Salazar [continuing]. You think, will drive the 
economics to be able to make this more than a test kind of 
project in Florida and Kentucky.
    Mr. Fulkerson. That----
    Senator Salazar. Let me--I've gone over my time by a 
minute, and I respect the chairman so much for letting me do 
that.
    Mr. Fulkerson. That's what you need.
    Senator Salazar. So, I yield back, Mr. Chairman.
    The Chairman. Thank you very much.
    Senator Corker.
    Senator Corker. Yes, sir. Again, Mr. Chairman, this has 
been an outstanding panel, and thank you for your leadership in 
putting it together, along with our ranking member.
    I know that one of the components of our biofuels bill 
limits the amount of corn to ethanol that's utilized, because 
there's concern, I guess, about the food industry and what's 
happening there. Yet, what I'm hearing from this panel today is 
that by using coal and biomass, we're actually able to take 
those same feedstocks, if you will, and cause them to go far 
further, putting less pressure on our food industry. Is that 
what I'm hearing? Does everybody agree with that?
    Mr. Fulkerson. That's what Bob Williams has shown. It's a 
very important--very important point. Very important point.
    Senator Corker. OK.
    I want to share the enthusiasm to plug-ins, by the way, Dr. 
Herzog. Let me just--you mentioned, in your written testimony, 
how, basically, coal-to-liquid technology uses a tremendous 
amount of water. I just wondered how that compared to the 
production of corn ethanol or cellulosic ethanol. How does it 
compare?
    Ms. Herzog. It's a good question. I'm actually not an 
expert on the biofuels process, so I'll have to get back to you 
on the answer to that.
    Senator Corker. Would it be reasonable to assume, though, 
that a large amount of water is used in both?
    Ms. Herzog. I simply don't know, for the biofuels process.
    Senator Corker. Well, it would be interesting for you to 
get back to us, or----
    Ms. Herzog. Yes.
    Senator Corker [continuing]. Someone else, because that was 
listed as a strong negative to this, and nobody knows.
    Mr. Bartis. The water--this is the water used in coal-to-
liquids. I can----
    Senator Corker. That's----
    Mr. Bartis. All coal and biomass to liquids, I can----
    Senator Corker. Yes.
    Mr. Bartis [continuing]. Report on that.
    The water use is highly dependent on how you design, and 
where you design, your plant. If you design a plant where water 
is not abundant, you will put in certain features in that 
plant--for example, dry-cooling towers--that cost more, but 
that allow you to use much, much less water. So, our estimates 
of water use is, it's widely ranging, depending on where you 
build the plant. It can be as low as a barrel and a half of 
water per barrel of product to as high as seven barrels of 
water per barrel of product, depending on what water costs and 
its availability.
    Senator Corker. OK. As I'm listening to the development of 
this technology, I know that in our own biofuels bill we're 
depending, in a big way, on cellulosic use. I mean, it's a 
technology that is not at commercial use today. Yet, we're 
depending upon that to reach these levels that we talked about. 
Where would you say we are in the development of coal-to-liquid 
technology as it relates to cellulosic technologies? It sounds 
to me that we may even be further down the road with this 
technology than we are commercially, using cellulosic.
    Mr. Bartis. Can I comment on that?
    Senator Corker. Yes.
    Mr. Bartis. We have looked at both.
    Senator Corker. OK.
    Mr. Bartis. Right now, I can say that there is not a 
doubt--there should be no doubt--that one can take biomass and 
put it into a gasifier and make liquids. That is a very, very 
low-risk option. We have looked, also, at the concept of taking 
cellulosic materials and making alcohols. Right now, we see no 
evidence that that option is a very high-risk option. There's a 
lot of money being invested in that option by the Government. 
It's a very high-risk option. We see no evidence that that 
option is going to be less expensive than the Fischer-Tropsch 
gasification option for straight biomass. When we add coal, 
there's a good chance it may be even less expensive. So, at 
this time, we can't say that--we have a near-term option, and 
we don't see the long-term option being much less.
    Senator Corker. Before you answer, Mr. Fulkerson, let me 
just generally ask this question, and you can answer this. I'm 
going to run out of time. It seems to me that the way we have 
now drafted this bill, we are picking winners and losers. It 
seems to me that we might be better serving our country by just 
setting standards, as Dr. Herzog has laid out, and many of you, 
and letting the market decide. It seems to me that we are 
listening to a very viable avenue today. Certainly, I think, 
plug-ins is going to be a very, very viable option down the 
road. It seems to me that we may be remiss in actually defining 
gallonage by certain sources, versus just setting a standard 
and letting that gallonage be in the mandate. Would you all 
agree or disagree with that?
    Mr. Fulkerson. I would certainly agree. I would certainly 
agree. In fact, in my testimony, these six policies I talk 
about are designed not to be technology-specific. The one 
advantage of cellulosic ethanol is that it doesn't require 
sequestration. It produces liquids that are carbon-free, 
effectively, without sequestration. All the coal and biomass 
gasification processes, in order to work as being neutral to 
the climate, require sequestration. So, I wouldn't give up on 
either one.
    Senator Corker. But we could set carbon standards----
    Mr. Fulkerson. And that would----
    Senator Corker [continuing]. With this, and we could 
solve----
    Mr. Fulkerson. Just then let the winner take all.
    Ms. Herzog. I obviously agree. Just one quick point. On the 
biomass co-firing gasification and coal-to-liquids process, we 
have one project in the Netherlands, maybe some demo runs have 
been done in the United States--it's far from clear to me that 
this is viable technology ready to jump out into the 
marketplace at this point in time.
    The Chairman. Let me just ask a question. I know Senator 
Craig is next, and then Senator Murkowski. But just following 
up on Senator Corker's point there. In the bill that we 
reported out of our committee, we provided--any new plants that 
were constructed to provide ethanol from corn, from traditional 
feedstocks, would have to be able to demonstrate--that the life 
cycle emissions of greenhouse gases were 20 percent less than 
in the case of gasoline. It was urged on us, although we didn't 
put it in the bill, and we may consider it again on the floor, 
that any ethanol produced from advanced biofuels, which was 
essentially cellulose-based ethanol, would be at least 50 
percent less in emissions--life cycle emissions than 
traditional gasoline. Are those the standards that you're 
talking about, that if those were in the bill, and applied to 
any gas--or any gasoline-equivalent-type fuel, you think that 
would be an appropriate way to go?
    Ms. Herzog. Yes, we think that's an appropriate standard. 
Then super-advanced would be 75 percent below.
    The Chairman. OK. All right.
    Mr. Fulkerson, did you have a comment on that?
    Mr. Fulkerson. Yes. It seems to me that the low-carbon fuel 
standard that is being developed in the State of California is 
one that should be very carefully considered. What it does is, 
it says, look, by 2017, or whatever, the zero--the fraction of 
the fuel that you use in your tanks should be 10 percent below 
what it is today, and it ratchets down from there. It doesn't 
specify a particular technology, it just simply says that the 
carbon--the net carbon emissions from that fuel--from the fuel 
that's used will be cleaner and cleaner with regard to carbon 
emissions----
    The Chairman. All right.
    Mr. Fulkerson [continuing]. And let whatever technology 
produces it----
    The Chairman. OK.
    Mr. Fulkerson [continuing]. Work.
    The Chairman. Very good.
    Senator Craig.
    Senator Craig. Thank you all very much. This is an issue 
that I know a little bit about, but not a lot, and you've added 
a great deal to my thought patterns today.
    Let me walk you through an interesting scenario that's 
happening as we speak. We're debating a bill on the floor of 
the U.S. Senate. In that bill is $0.5 billion for timber-
dependent schools and counties. Half a billion a year. OK? In 
that bill is also $0.5 billion to fight fires. We spent $2 
billion last year fighting fires on our public lands. We've got 
$840 million in Interior approps for firefighting, also. So, 
we'll spend maybe $1.5 billion fighting fires on our forested 
lands. You can run the numbers right now. So, we're going to 
spend a couple of billion dollars a year doing something that 
we could stop doing if we did something else, but we chose not 
do that, as a country.
    Here is what we're not doing, if you're interested in 
fiber. Biomass. We've got 100 million tons of dead wood on the 
floor of our forests today. We're growing 16 million tons a 
year that are off limits until Mother Nature takes them away in 
the form of a release of carbon into the atmosphere when she 
burned 10 million acres last year. Probably the greatest carbon 
release in the history of our country occurred last year. But, 
because it was natural, it didn't hit anybody's Richter scale 
of alarm. But it certainly was carbon.
    A healthy forest is a sequestering forest. I'm not sure I 
understand this picture very well anymore. We're talking about 
switchgrass and farmers and all of that which is available, and 
yet, there's 100 million tons laying out there, and 16 million 
tons a year grown, and we're subsidizing schools and counties 
because we wouldn't let them touch the forests anymore, and now 
they're poor. They were once rich. We have tens of thousands of 
people out of work who once used to work in our forests.
    I'm not suggesting getting back to a green sale program, 
I'm talking about going in and thinning and cleaning and going 
after the largest quantity of biomass laying out there that 
Mother Nature is rapidly converting into carbon and sending it 
into the atmosphere again. You're talking about technologies 
that, blended with the diversion of $2 billion a year out of 
our Treasury that we're currently using to fight fires and 
supplement schools into technology--it would seem to make a lot 
of sense.
    Now, I'm going to suggest you can't get to all of that 
wood. Wouldn't be natural to, it wouldn't be environmentally 
sound to do so. But it would certainly be environmentally sound 
to go after a great deal of it.
    What's wrong with that picture?
    Yes?
    Mr. Fulkerson. There's nothing wrong with that picture. The 
residues from agriculture and forests are a great source of 
biomass for energy. You can use the gasification process in 
order to realize that. So, that's a very good source. There's 
nothing wrong with that.
    Senator Craig. Doctor.
    Mr. Fulkerson. I mean, you don't want to ruin the forests, 
but----
    Senator Craig. No, no.
    Mr. Fulkerson [continuing]. As long as you do it carefully.
    Senator Craig. Well, I look across the landscape of my 
State today, with thousands of acres dead, bug-killed, can't 
touch it.
    Mr. Fulkerson. Yes.
    Senator Craig. They're not sequestering one ounce of carbon 
because they're a dead forest. But a young, viable, diverse 
stand forest is rapidly grabbing the carbon and putting it into 
the wood.
    Yes, Doctor.
    Ms. Herzog. One thing I firmly believe is not to comment on 
something I don't know very much about, which is forest science 
and policy. However, we do have experts in our organization, 
and I'd love for them to come in and brief you on this issue in 
detail. There are, from what they believe, environmental 
impacts from going into forests----
    Senator Craig. Sure.
    Ms. Herzog [continuing]. And trying to collect all this 
waste, biomass material, on the ground. So, we actually have 
put together what we believe are decent sustainability criteria 
for collecting biomass, which, as I said, I'd love to have our 
experts----
    Senator Craig. Yes.
    Ms. Herzog [continuing]. Come in and brief you.
    Senator Craig. No, entry has impact, there's no question 
about----
    Ms. Herzog. Right.
    Senator Craig [continuing]. That. That's a valid thought.
    Anyone else wish to comment?
    Mr. Ratafia-Brown. Senator, the only thing I'd like to say 
is--I'm not a forestry expert, myself, either. This becomes an 
economic issue, as far as collection. As I talked, in my 
testimony, about energy density of wood products is far less 
than something like coal, you pretty much have to try to 
increase the density of the material, perhaps on a regional 
basis, to make it more available to a larger-scale facility.
    Senator Craig. Well, I appreciate that. But I also 
appreciate the blending ideas that you're talking about in 
these new concepts. Would seem to make a good deal of sense.
    Mr. Ratafia-Brown. No, I agree. I think it's a matter of 
getting the product to the large-scale----
    Senator Craig. Yes.
    Mr. Ratafia-Brown [continuing]. Gasification facility. That 
is a big issue here. As far as--again, we have a very 
distributed----
    Senator Craig. Yes.
    Mr. Ratafia-Brown [continuing]. Energy source. It's not 
like coal, that's very energy-dense. Wood and----
    Senator Craig. Right.
    Mr. Ratafia-Brown [continuing]. Wood waste is not. You 
might want to pelletize it, you might want to do something--
what we call torrefaction----
    Senator Craig. Sure.
    Mr. Ratafia-Brown [continuing]. To increase the energy 
density. But I agree with your comment.
    Senator Craig. Thank you.
    Did you have a comment, Jim?
    Mr. Bartis. We have also looked at this issue, and we 
don't--we think small may be beautiful in this case, in that 
some of concepts for very large plants that are generally 
associated with coal only, make more sense when we get a lot 
smaller and look at coal or biomass together. So, this is a----
    Senator Craig. Yes.
    Mr. Bartis [continuing]. Fantastic opportunity for the 
research program to look at whether we can do this at a much, 
much smaller scale, comparable to the scale of typical biomass 
facilities.
    Senator Craig. Yes, David.
    Mr. Denton. Yes, I'd just like to add a bit, that biomass 
is not biomass, that there are different classes of it, just as 
there are different classes of other feedstocks. Wood waste, in 
particular, are ones that, because of their nature, may require 
some different technologies in gasification than others. I know 
when Polk fed eucalyptus, as well as switchgrass, the 
switchgrass ran fine. They both gasified fine. The problem was, 
wood was, you know, getting involved in some of the check 
valves, plugging up things in those----
    Senator Craig. It has lignins in it, yes.
    Mr. Denton. There are other issues----
    Senator Craig. It does create those kinds of problems.
    Mr. Denton. So, it will----
    Senator Craig. Right.
    Mr. Denton [continuing]. Involve some technology 
development to probably--but I know there are people looking at 
that----
    Senator Craig. Yes.
    Mr. Denton [continuing]. Right now.
    Mr. Ratafia-Brown. David, that was a relatively minor 
problem at that facility.
    Senator Craig. Yes. Well, they do yield differently. Well, 
thank you all very much for that.
    One of the problems we're struggling with here--and 
certainly the Chairman and I and all of us of this committee 
have been involved in it--as we've changed the way we manage 
our forests, we have, in a healthy forest policy, attempted to 
get in and thin and clean. But there's no value to it. We're 
not allowed to place a value on it, nor does little value come 
from it. As a result, we subsidize it, we pay for it with your 
tax dollars. Therefore, we can't do as much as we ought to be 
doing in relation to the general health of our forests. The 
opportunity to add value to it, from that standpoint, in these 
concepts, seems to be the right dynamic.
    But, anyway, thank you all very much for your testimony and 
your involvement.
    The Chairman. Senator Murkowski.
    Senator Murkowski. Thank you, Mr. Chairman. Thank you, to a 
very interesting panel this morning. I appreciate all that we 
have heard.
    I had an opportunity yesterday to sit down with a group of 
individuals, primarily from the electric industry, and we were 
talking about coal and the technologies, and how we move 
forward with the pilot projects, demonstration projects. Of 
course, the question that then has to come up is, ``It's great 
to be focused on the technology that is coming, and how we're 
going to utilize this in the new plants that we build, but what 
about the existing facilities across the country?'' I would 
like to hear from you this morning whether or not you believe 
that we have the technology today to help capture and sequester 
from existing plants through our ability to retrofit. If we 
don't have the technology, how long until we do have that? What 
do we do with these existing facilities out there?
    Mr. Denton.
    Mr. Denton. Yes. As I mentioned in my testimony, one of the 
advantages of industrial gasification--I think this is where 
you can maybe get the jumpstart--is that those technologies, by 
and large, already require capture of carbon. For example, our 
facility in Kingsport, we have to capture the CO2 
before it goes forward in our process, any CO2 that 
we've formed, primarily due to the shift reaction, where we 
actually convert some of the carbon monoxide to carbon dioxide 
while forming more hydrogen for our purposes of chemical use. 
So, when you do that, you're going to already have carbon 
capture, so you've got a nice place in an existing facility 
where you have a concentrated stream of CO2 that's 
already captured, so it kind of gets you beyond that first step 
of two parts of carbon capture and sequestration, the capture 
and the sequestration, so you're halfway there. So, I think 
that is a good way to get a headstart on----
    Senator Murkowski. So, we're there with the capture. Are we 
there with the sequestration?
    Mr. Denton. Right. On the sequestration, the good thing is 
some of the places where, particularly, these industrial plants 
are being looked at because they're tied to chemical markets, 
which currently exist, for example, a lot of them, along the 
Gulf Coast--is your inner region that has, also, a lot of oil 
recovery development, so there is the potential to look at 
sequestration in enhanced oil recovery applications. The Gulf 
Coast also has quite a bit of deep saline aquifer potential, as 
well. So, you're located in an area that has some good 
sequestration potential.
    Senator Murkowski. What if you're not?
    Mr. Denton. Well, it depends on where you're located. If 
you're not, then you're going to be looking at what other 
options you have. If it's coal-based, you may be in a very good 
location for enhanced coal-bed methane. So, you have to look at 
all the different options that you have in front of you. But, I 
think, in most cases, there will be some type of sequestration 
option. Then the only issue is the cost penalty to go from the 
captured carbon that you already have to sequestration.
    Senator Murkowski. Do we need to be doing more here, from 
the Federal perspective then, whether it's tax credits or 
grants--what should we be doing to make sure that the focus is 
not just on the new facilities that may be coming online within 
the balance of this next decade, but in retrofitting? Are we 
doing enough, from a policy perspective? This goes out to 
anybody.
    Mr. Denton. I think one of the things that has been talked 
about is the--taking some sort of credit--maybe it's a 
production tax credit or whatever--to help cover the cost of 
that sequestration piece. If you had that in place today, folks 
that already have that captured carbon could be doing something 
with it and helping advance the technology. So, yes, I think 
there is a role for incentives for that.
    Senator Murkowski. Anybody else?
    Mr. Bartis.
    Mr. Bartis. I believe that two things are necessary. First, 
and most importantly, is to reduce the uncertainties and pass 
legislation that sets up the framework by which carbon dioxide 
will be controlled. The sooner we do that, the more we're going 
to get new plants properly built, and the more we're going to 
have private industry and all of its innovative capabilities 
working on the retrofit problem.
    Now, with regard to the retrofit problem, that's an 
extremely important problem. I presume you're talking about the 
huge investment in existing coal-fired power plants. We do not 
have technology available today, any means, that allow the 
capture of carbon dioxide from those existing plants at 
reasonable cost. It hasn't been proven. At any----
    Senator Murkowski. How far away----
    Mr. Bartis [continuing]. Reasonable cost.
    Senator Murkowski. How far away are we from that 
technology?
    Mr. Bartis. I can't tell you that part. I know it's a topic 
of research, and it's an extremely important research topic in 
the Department of Energy.
    Senator Murkowski. Anybody else?
    Mr. Ratafia-Brown.
    Mr. Fulkerson. There is a fellow at Carnegie Mellon, Ed 
Rubin, that has spent a reasonable amount of his career on 
exactly the question that you're asking, and he would be a 
really good person to discuss this with. I could certainly put 
you in touch----
    Senator Murkowski. I'd appreciate that.
    Mr. Fulkerson [continuing]. With him. I think he can help.
    Senator Murkowski. Great.
    Mr. Ratafia-Brown.
    Mr. Ratafia-Brown. Well, let me just say, as far as the 
technology goes, I agree with Jim, the problem with the capture 
from an existing coal-fired power plant is that the 
CO2 concentration in the plant flue gases is too 
low. It's not nearly as high as it is in the gasification 
facility. But there are some ways that one could introduce 
biomass. It's already done. You want to introduce biomass, like 
wood products, directly into a boiler, or you--or you use a 
gasifier prior to the boiler, you gasify the material, and you 
feed this gasified material right into a coal-fired boiler, so, 
thereby, gaining the benefit of the biomass use, which 
effectively reduces your CO2.
    The other technologies that are being worked on are 
basically using oxygen instead of nitrogen--instead of air, I'm 
sorry--as the oxidant for these power plants. If you use 
oxygen, you end up with just CO2, and, therefore, 
you have a much higher concentration of CO2, which 
will much more effectively allow us to sequester--or capture 
the CO2 from existing power plant flue gas. There 
are a variety of technologies that are being researched through 
the Department of Energy for this purposes.
    So, there are the means. Again, it's a matter of cost-
effectiveness and providing more funding for that R&D, but it's 
doable.
    Senator Murkowski. Thank you.
    Mr. Chairman, I would suggest that, as we move forward in 
these areas--there's been a lot of focus on this new technology 
in the demonstration projects, which is very, very important, 
but I think we also need to remember as is pointed out, the 
incredible infrastructure that is already in place, that 
probably has decades of useful life in them. But if we can't 
allow for some form of retrofitting, we're not going to be 
seeing the reductions in emissions that we would like. So, I'd 
like to work with you on that.
    The Chairman. No, that's a very good point. I appreciate it 
very much.
    Senator Tester, go right ahead.
    Senator Tester. Thank you, Mr. Chairman. I appreciate you 
holding this hearing. I appreciate the panel to be there. I 
apologize, I got out of doing the floor thing for a bit to come 
ask you guys questions.
    This issue is critically important to me and--quite 
frankly, because of the coal reserves we have in Montana. I 
think there's tremendous opportunity. When I first heard about 
the coal-to-liquids, I was really, really enthused. Then, the 
issue of CO2 started coming up more and more.
    I just wanted to ask--as coal-to-liquid related to coal-
fired electricity, I might add, it wasn't at a zero-based 
standpoint. Let's start at the end and work back--if you've got 
a gallon of petroleum diesel fuel and you've got a gallon of 
diesel created from coal, and it's burnt in the same vehicle, 
do they emit the same amount of CO2?
    Go ahead Mr. Fulkerson.
    Mr. Fulkerson. The coal-derived liquids would vent twice as 
much CO2, approximately.
    Senator Tester. I'm not talking about the process before, 
in the manufacturing of the fuel, I'm talking a gallon to a 
gallon burned in the vehicle, we're not doing anything----
    Mr. Fulkerson. Oh. Oh, gallon for----
    Senator Tester. Gallon-to-gallon.
    Mr. Fulkerson. Same amount. Same----
    Senator Tester. Same amount, OK. As the process goes--well, 
step backward another time. Now we've taken the coal. It's in 
gas form. It's my understanding it goes from gas form to liquid 
form. Is that where the bulk of the CO2 is 
generated? It is.
    So, Mr. Denton talked about the Eastman Chemical Company. 
You're taking it from coal to gas, and using it in natural gas 
form for your processes. How much CO2 is emitted in 
that process, compared to coal-fired electrical generation?
    Mr. Denton. Well, in our case, it's a lot less, because 
keep in mind, we convert a good proportion of the carbon that 
comes into the feedstock into actual product.
    Senator Tester. OK.
    Mr. Denton. We're trying to convert that carbon into 
product. We make, as a sidestream, some CO2, but 
that is captured by the process.
    Senator Tester. That's good.
    I want to step over to Mr. Fulkerson again on--I believe 
his name is Bob Williams that you're taking the place of. You 
did a fine job in your presentation, I might add; he's got 
nothing to be ashamed of there. I couldn't crack the part about 
biomass negative value and carbon resulting in a negative value 
in carbon emissions. In other words, in my head, if I plant a 
tree, and that tree gets big, it absorbs a lot of carbon in 
that process; I've made a difference in global warming. Now, if 
I take that tree and I cut it down and I burn it, I haven't 
done anything from the time I started the tree until I burn it. 
So, how--and I assume that the process of mixing biomass with 
coal includes burning that biomass. How can it be a negative 
value?
    Mr. Fulkerson. Well, it's negative, just--the fact is that 
it takes carbon out of the air to grow the tree or----
    Senator Tester. But don't you release it again in the 
burning?
    Mr. Fulkerson [continuing]. Switchgrass, or whatever, 
prairie grass, right?
    Senator Tester. Right.
    Mr. Fulkerson. OK. Now, you take carbon, and you now 
sequester it. You put----
    Senator Tester. Yes.
    Mr. Fulkerson [continuing]. Put it through the process, and 
you sequester it.
    Senator Tester. Oh, I see what you mean. You're talking 
about at the other end. The----
    Mr. Fulkerson. Right.
    Senator Tester. OK. So, the question I have is, and I think 
you said this, so I think you're going to tell me what I 
already know, but I want to make sure--``Do we have the 
capability right now to capture carbon on a large-scale basis 
with the current technology we have?''
    Anybody can answer it.
    Mr. Fulkerson. Yes, we do have the capability of doing it. 
But we don't have any large-scale----
    Senator Tester. Demonstrations.
    Mr. Fulkerson [continuing]. And storage of carbon from 
present facilities in the United States.
    Senator Tester. Gotcha. The----
    Go ahead.
    Mr. Bartis. We have opportunities to capture carbon from a 
few plants. The primary opportunity is to use it in enhanced 
oil recovery. There is a good chance--and there doesn't seem to 
be any showstoppers available--that we can do geological 
storage of carbon dioxide. There's also approaches to store 
carbon--well, I guess coal bed--you can store it in coal seams. 
So, there's a very low-risk approach, but it's never been 
demonstrated.
    Senator Tester. OK.
    Mr. Bartis. All right? That demonstration is expensive, but 
absolutely critical.
    Mr. Fulkerson. Senator, there is a demonstration right near 
you, in North Dakota, and that's the Great Plains process, 
which sequesters--which doesn't sequester, but it separates 
out--it sends 160 million cubic feet per day to Saskatchewan to 
use for enhanced oil recovery.
    Senator Tester. I've gotcha.
    Go ahead, Mr. Denton.
    Mr. Denton. Yes. In terms of carbon capture and 
sequestration, as I mentioned, it is technically feasible. 
There is no problem. We've been capturing carbon for two 
decades. As Senator Dorgan mentioned that North Dakota 
gasification, they are actually putting CO2 in the 
ground from enhanced oil recovery. I think the real problem is 
beyond that. When you beyond enhanced oil recovery, there are 
issues, beyond technical feasibility, that haven't yet been 
addressed, and that's stuff like, Who owns the rights, the 
property rights, to that? Who takes the ultimate liability? 
What are the requirements by EPA of permitting, say, putting 
CO2 into a saline aquifer? There's just a whole lot 
of other issues around that, that have not been addressed yet, 
that are the problems right now, not the technical feasibility.
    Senator Tester. So, what you're saying is, we have the 
technical feasibility to be reasonably sure--because nothing's 
ever 100 percent, besides death and taxes--but reasonably sure 
that that CO2 is going to stay in the ground if we 
sequester it there?
    Go ahead.
    Mr. Bartis. We should be optimistic that that will be the 
case. That's for one reason--that's the primary reason why RAND 
suggests we do something with regard to coal-to-liquids. But, 
until we have multiple large-scale demonstrations----
    Senator Tester. Gotcha.
    Mr. Bartis [continuing]. We're not going to be there.
    Senator Tester. OK.
    Mr. Bartis. None are planned.
    Senator Tester. OK.
    I want to talk about water for just a second. I apologize 
if these are repetitious questions. I want to talk about water, 
and how much water is required to produce a gallon of coal-to-
liquids. Can you give me any idea on how much that would be?
    Mr. Bartis. Yes, I don't----
    Senator Tester. For, let's say, gallon-to-gallon.
    Mr. Bartis. I'll repeat what I said earlier.
    Senator Tester. OK.
    Mr. Bartis. Gallon to gallon, it depends on what you do 
when you design the plants. If you design the plants in an area 
that is--that doesn't have lots of--has limited supplies of 
water----
    Senator Tester. Yes.
    Mr. Bartis [continuing]. You're going to put in certain 
design features that save water. If you design the plant where 
water is abundant, you won't put those features in.
    So, our best estimate is, for all--the locations that are 
poor in water, probably 2 gallons of water per gallon of fuel. 
In areas that are very rich in water, possibly up to 7 gallons 
of water per gallon of fuel.
    Senator Tester. Does it cost more to--I would assume it 
would cost more to build the plant that would be water-
restrictive.
    Mr. Bartis. Yes.
    Senator Tester. What does that do for competitiveness, as 
far as barrel of oil?
    Mr. Bartis. I have not looked at those----
    Senator Tester. OK.
    Ms. Herzog.
    Ms. Herzog. Yes, I just wanted to--I agree that, obviously, 
you will have a range, and the technology can be done to reduce 
water use. Our estimate is, on average, about 5 gallons per----
    Senator Tester. OK.
    Ms. Herzog [continuing]. Per ton of coal, which completely 
fits into that range.
    Senator Tester. Yes.
    Ms. Herzog. But I'm perhaps a little less optimistic that 
the best plants will be built in the right places----
    Senator Tester. Yes.
    Ms. Herzog [continuing]. As I'm sure you're aware.
    Senator Tester. Well, I can tell you that, you know, a lot 
of people have died over water over our history, and it's a 
critically important piece of survival.
    About a month ago, maybe less, with the bill that's going 
to be on the floor, there was an amendment offered to require--
it was a mandate for synfuels--coal-to-liquids. I can't 
remember what the amount was, but it was fairly significant. 
There was some difference of opinion as to whether that's the 
right direction to go, whether to require a mandate first, or 
to--well, I don't want to put words in your mouth. But what I'm 
hearing you folks say--and just tell me if this is correct--if 
you were in my position, the first step you would do, from what 
I'm hearing, is that you would create a large-scale 
demonstration project, maybe two or three of them? Is that what 
I'm hearing? Or am I hearing something else?
    Go ahead.
    Ms. Herzog. I'm sure others will jump in with some----
    Senator Tester. Yes.
    Ms. Herzog [continuing]. Technical details, but the--it was 
21 billion gallons of liquid coal by 2020--
    Senator Tester. Right, that was it.
    Ms. Herzog. It's approximately 40 medium-sized plants. It 
was a requirement to be equivalent to gasoline. The key part is 
the standard associated with the plants. The demonstration 
plants could make sense, but they have to be doing what we need 
them to do, which is actually better than gasoline. They have 
to be doing better, in greenhouse gas life cycle emissions, 
than gasoline. We would say 20 percent or more.
    Senator Tester. Good point.
    Further comments on that point?
    Mr. Bartis. We have looked at this issue, and our view is 
that we--it's important that we go ahead with a few. I wouldn't 
call them ``demonstrations,'' but I believe it's very important 
that we go ahead with a few, where ``a few'' is up to more 
politically astute persons than I. But it's important to get 
progress in this area.
    The reason we're saying ``a few'' is that we haven't--we're 
not certain about all--how carbon is going to be managed, and 
we're not certain about the prices of these plants. Now, it's a 
little unfair that I'm only talking about coal, so to be--to 
put this in proper context, this all--this same recommendation 
by RAND would also apply to any incentive that is calling for 
large amounts of any unconventional fuel, including ethanol 
fuels. We would say it's premature to do that.
    Senator Tester. OK. Well, you know, it's unfortunate that a 
person doesn't know more about stuff than you do. You know, as 
a farmer, I take pride in knowing a lot of stuff about a 
little, when it comes to making hay or harvesting crops or 
fixing a combine or whatever. I've always approached this coal-
to-liquids from a standpoint that we need to build a 
foundation, and that foundation revolves around carbon capture 
and carbon sequestration. It's easy to talk about. I mean, 
that's pretty straightforward. The question is, ``How do you 
get there? How do you have grants that are applicable for 
carbon capture and sequestration?'' How do you give tax 
credits? How do you get there? How do you get that research 
going with the sense of urgency that I truly feel?'' Especially 
after being in Glacier Park last weekend and seeing what's 
going on there, from a climate standpoint.
    Mr. Denton. I think I mentioned earlier, I think the 
quickest way still is through some of the industrial 
gasification opportunities where you already have carbon 
captured. You don't have to do this, all of it, in an 
integrated facility. If you're wanting to evaluate carbon 
capture and sequestration, go to where you already have carbon 
captured in a cheap way to get that sequestration step proven. 
If you want to illustrate coal/biomass, you go to where it 
makes sense to do that. Then you start putting those pieces 
together, and maybe--and I think there is a value to--at some 
point, of having a few--as you mentioned--a few of these coal-
to-liquids plants with the right kind of configurations to 
evaluate what you want.
    Senator Tester. Yes, go ahead.
    Mr. Ratafia-Brown. I would just like to say, with regard to 
investment tax credits, we run the National Energy Modeling 
System, the same one that EIA runs, and what I have found with 
advanced technologies is that, when you do provide that 
investment tax credit, that incentive, that you can get much 
earlier penetration of advanced technologies, at least get them 
in to the marketplace, well before they might otherwise because 
of that advantage of the lower cost and being able to compete 
better.
    Senator Tester. OK.
    Mr. Fulkerson. You've got to--if you want to solve the 
problem, you've got to tax carbon emissions. You've got to put 
an incentive there that sets the market. I assume that that's 
what all the bills in Congress, and all the debates, are 
primarily about now, is----
    Senator Tester. Carbon taxes?
    Mr. Fulkerson. Yes. Well, carbon----
    Senator Tester [continuing]. Make that----
    Mr. Fulkerson [continuing]. Tax, cap-and-trade, whatever. 
But you've got to put the policies in place that will make 
people be inventive about the ways in which to meet it.
    Senator Tester. So, what you're saying, until industry gets 
to a point where they're between a rock and a hard place, 
they're going to coast?
    Go ahead. I mean, you deal with them----
    Mr. Fulkerson. That's what I would do.
    Senator Tester. OK.
    Mr. Bartis. I'd like to build upon that statement, though. 
I mean, I fully agree that it's very important that we put the 
framework out there. But let's also remember that we have a 
problem with importing oil from----
    Senator Tester. Oh, yes.
    Mr. Bartis [continuing]. OPEC. We have looked at carbon 
taxes, or cap-and-trade, where--on valuing carbon dioxide, 
basically. There is low-hanging fruit out there. The low-
hanging fruit is coal-fired power plants, and any centralized 
use of coal, including these coal-to-liquid plants. But if you 
put the kind of value on carbon dioxide that motivates capture 
from these large facilities, you haven't done anything with 
regard to influencing the problem of imported oil. That carbon 
tax, a $30 carbon tax, or a $30 cap-and-trade system, that's 
only going to raise the price of oil about--gasoline about 30 
cents. That's not going to motivate much. It's not going to 
motivate much conservation. So, you need to go beyond just 
looking--there are two different problems. There's a 
CO2 problem, and there's also an energy problem.
    Senator Tester. Yes, I gotcha there.
    Ms. Herzog. Yes. No, I completely agree that just putting a 
cap on the emission state of transportation fuels won't 
necessarily drive us to cleaner fuel or vehicle technology. 
That's why we believe that you actually also need complementary 
policies to make sure that you expand the fuel sources to be 
more diverse while meeting certain standards. You can have an 
oil-reduction standard, you can have a greenhouse gas standard. 
This would be a low-carbon fuel standard, which would ratchet 
down over time. This would be greenhouse gas tailpipe emission 
standards, which would make our vehicles cleaner, as well.
    Senator Tester. Go ahead, Mr. Denton.
    Mr. Denton. Yes, in terms of the topic of taxing carbon, I 
do want to throw a word of caution here, that, particularly in 
our industry, we are in a global industry, and we're seeing 
this daily. We're seeing jobs from the United States go 
overseas because we are not competing on the energy cost of 
living in the United States. If you tax, or you do anything 
that puts a cost to just the U.S. industry, what you're going 
to see is the actual opposite of what I think you want, that 
you're going to see those jobs go overseas to operate 
facilities that are not going to do any of this, and put the 
emissions into the air. So, we have to be careful about it. I 
think, start with incentivizing, getting some of these going, 
until you can get the market in place, get some of these other 
issues in place, and see a global marketplace that addresses 
that issue.
    Senator Tester. I understand.
    Mr. Ratafia-Brown. Yes, I'd like to go back to Senator 
Murkowski's comment about retrofitting. If you put a heavy tax 
on carbon, generally what happens is--it's the electricity 
sector that takes the brunt of it. They are the most elastic, 
in terms of the ability to control. Again, I've run so many 
cases of energy bills, looking at different carbon taxes, and 
what happens is those existing power plants end up being 
retired very quickly, to the detriment of the industry.
    Senator Tester. I appreciate all of your comments. I will 
tell you that I think the last thing that anybody on this 
committee wants to do is increase taxes. But I will also tell 
you that there has to be a sense of urgency, that I feel in 
this body, but I don't necessarily feel out in the hinterlands 
amongst industry. That's not a bad thing about--I'm not 
badmouthing industry at all. I'm just saying that the folks 
that are doing the carbon capture, I think, have a tremendous 
opportunity to make a ton of money by taking that technology, 
and refining it, and taking it throughout the world.
    I hear what each one of you are saying, and I think they 
all have merits. I appreciate the comments from each one of 
you. I just want to say this. I appreciate you guys taking the 
time and coming up here and talking to us truthfully on your 
lifetimes of experiences dealing with coal and coal-to-liquids 
and coal-to-gas and the environment. I think we all understand 
the tremendous opportunity there is here, and also what a 
tremendous challenge it is to try to make this country energy 
independent, while satisfying the environmental concerns that 
are out there.
    So, thank you very much.
    The Chairman. Thank you.
    Thank you all, again, for coming. This was an excellent 
hearing, and we appreciate your good advice.
    [Whereupon, at 11:40 a.m., the hearing was adjourned.]
                                APPENDIX

                   Responses to Additional Questions

                              ----------                              

      Responses of David Denton to Questions From Senator Bingaman
    Question 1. You testified about the relative ease, compared to 
IGCC, that industrial gasification facility could get to 90% capture of 
feedstock carbon. This would seem to present a real opportunity to make 
progress on lifecycle emissions compared to natural gas as a feedstock 
if biomass is incorporated in a substantial way. How much opportunity 
is there to incorporate biomass into the process?
    Answer. Gasification technology is relatively feedstock flexible 
and thus certainly has potential for incorporation of biomass as a 
feedstock. But this potential is dependent upon the type of biomass and 
upon the specific gasification technology that is used. For example, 
biomass used in slurry-fed gasifiers must be in a form suitable for use 
in the high-pressure slurry pumps used to feed the gasifiers. One must 
also keep in mind that biomass feedstocks have only been demonstrated 
to date as relatively minor co-feeds in commercial-scale gasifiers. 
Feed of significant quantities of biomass to a commercial-scale 
gasifier would require a step increase in overall project risk, an 
increase that may be difficult to project finance until a few 
commercial-scale demonstrations have occurred. For example, it is 
highly likely that biomass and coal feedstocks, if co-fed to a 
gasifier, would react at different rates (i.e., one of the feedstocks 
would react with oxygen faster than the other, resulting in over-
oxidation of one feedstock and under-oxidation of the other), making 
control of outlet syngas composition more difficult. Feed of 
significant quantities of biomass to commercial-scale gasifiers also 
faces other market and risk issues that have not yet been resolved, 
such as obtaining long-term (20+ years) assured supply of large 
quantities (up to thousands of tons per day) of adequately dried and 
stored biomass within a reasonable (50-mile or less) radius of the 
gasification facility and at an acceptably low long-term feedstock 
price. Industrial gasification projects already face multiple siting 
issues--e.g., being close to an inexpensive coal/petcoke feedstock 
source, close to markets for the desired end products and to acceptable 
outbound logistics, and close to suitable long-term carbon dioxide 
sequestration reservoirs. Adding a further requirement to be sited near 
suitable biomass feedstock supplies could severely limit the options 
for siting such facilities. However, to the extent that selected sites 
can accommodate biomass feedstocks, opportunity does exist to pursue 
such co-feeds over time as the above-mentioned market and risk issues 
are addressed.
    Question 2. If you do feed biomass into a coal gasification process 
what kind of reductions in lifecycle emissions do you estimate would be 
achievable as compared to other fossil fuel feedstocks?
    Answer. Lifecycle gasification emissions of any feedstock are 
dependent upon the composition of the feedstock and upon the design of 
the syngas cleanup process. These variables are somewhat independent, 
so it would be difficult to say what, if any, overall lifecycle 
emission reductions might occur by co-feeding biomass. To the extent, 
however, that any carbon dioxide formed in the process is sequestered, 
the overall lifecycle emissions of carbon dioxide to the atmosphere 
would be reduced if one includes the extraction of carbon dioxide from 
the atmosphere by the growing biomass.
      Responses of David Denton to Questions From Senator Sanders
    Question 3. The Intergovernmental Panel on Climate Change has 
recently issued its Fourth Assessment Report Summary for Policy Makers. 
In that Report they concluded that the evidence that global warming is 
real and caused by humans is unequivocal. The MIT study, ``The Future 
of Coal,'' suggested that Carbon Capture and Storage (CCS) may increase 
the cost of electricity from coal by 20%, but an aggressive energy 
efficiency campaign could be conducted, so that less electricity is 
used, bringing our electricity bills down by 20% or more. What do you 
see as the cost of liquid fuel (diesel) and gaseous fuel from coal and/
or coal-biomass with CCS versus conventional diesel and natural gas in 
the near term and long term?
    Answer. Eastman has not yet had occasion to conduct a detailed 
calculation of the cost of diesel and synthetic natural gas with CCS. 
There have been studies reported by others, such as the DOE, which 
reference such cost comparisons. However, the percentage of added cost 
for CCS would be expected to be less for products such as diesel and 
synthetic natural gas (methane) than for electric power, because the 
processes required to produce diesel fuel and methane, just as with 
other industrial gasification processes, already incorporate capture of 
most of the carbon dioxide formed in the process, whereas capture of 
the carbon dioxide would be an added step for production of electric 
power. As technologies such as coal-to-liquids and coal-to-methane are 
commercialized and deployed, one can reasonably expect the costs to 
produce such products to drop over time as the processes are improved 
and first-of-a-kind risks are reduced.
    Question 4. I join Senator Murkowski in her concern about the need 
to retrofit our existing coal fired power plants to address the issue 
of carbon capture and storage. Some of the testimony suggested that 
adding ``oxyfuel'' to these older plants would be the best path to take 
as this burns pure oxygen, instead of outside air, producing a carbon 
dioxide-rich exhaust stream, with little or no NOX, so the 
CO2 is more concentrated and easier to capture for 
sequestration. Do you have any information on the ease/feasibility of 
retrofitting older coal plants or other coal-burning industrial 
facilities with ``oxyfuel''?
    Answer. Eastman has not directly evaluated ``oxyfuel'' combustion 
as a retrofit for existing coal-fired power plants. However, one could 
reasonably assume that ``oxyfuel'' retrofit of existing boilers could 
be problematic because most of these boilers were not designed to be 
air-tight. Any in-leakage of air to older boilers would introduce 
nitrogen diluent into the system and defeat, to some extent, the 
purpose of adding ``oxyfuel'' combustion. So the success of ``oxyfuel'' 
retrofit of existing boilers could be dependent upon how well the 
boilers can be sealed to prevent such in-leakage of air. Also, it is 
not at all clear that introduction of pure oxygen to boilers would not 
result in substantial increases in NOX emissions from such 
boilers (due to higher flame temperatures) without the addition of a 
substitute diluent such as recycled carbon dioxide. In addition, one 
would still need to remove sulfur and other contaminants from the 
exhaust gas prior to sequestration of the carbon dioxide (for most such 
applications), and it is unclear what retrofits would be required to 
those existing downstream cleanup steps (such as scrubbers) to enable 
``oxyfuel'' retrofit of the main boilers. However, the proponents of 
``oxyfuel'' combustion are working to try and address all of these 
issues.
      Responses of David Denton to Questions From Senator Salazar
    Question 5. It appears from the written testimony, that liquid 
fuels produced from coal combined with biomass can result in lower 
greenhouse gas emissions than conventional gasoline. What are the 
technology hurdles to overcome in mixing biomass with coal to produce 
liquid fuels? Has the combination of biomass and coal been used at any 
commercial plant? What is a realistic percentage of greenhouse gas 
emissions compared to petroleum that we can expect to achieve?
    Answer. See the response to question No. 1 above.
    Question 6. Even with the use of biomass, there are still 
substantial volumes of CO2 that must be captured and safely 
stored. Are there any recommendations this panel has on where to locate 
CTL facilities to facilitate the storage of CO2?
    Answer. To facilitate the storage of CO2, one must be 
near an adequately-sized geologic reservoir suitable for long-term 
storage of the CO2. The DOE (Office of Fossil Energy/NETL), 
through cooperation with its Regional Carbon Sequestration 
Partnerships, has recently developed a Carbon Sequestration Atlas that 
identifies a number of suitable geologic reservoirs across the United 
States and Canada. Obviously, the most economic CO2 storage 
alternatives would involve sequestering the CO2 in 
productive applications such as enhanced oil recovery or enhanced coal 
bed methane.
    Question 7. Can you discuss the water requirements for a CTL plant? 
Are there opportunities for reusing/recycling water in the process?
    Answer. Eastman has not yet calculated the water requirements for a 
CTL plant. Depending on the composition of various water streams, there 
may be opportunities to recycle or reuse some of the water streams, 
such as in preparation of coal-water slurries to feed to the gasifiers. 
However, such recycle or reuse may require treatment of the water 
stream to remove specific impurities that might otherwise buildup in 
the recycle stream.
    Question 8. The auto industry has developed plug-in electric 
hybrids, and this committee has heard testimony about all-electric 
cars. Can you discuss the advantages and disadvantages of using coal to 
produce liquid fuels vs. using coal to generate electricity to charge 
batteries for electric cars and hybrids?
    Answer. Both alternatives offer opportunities to utilize coal to 
reduce our dependence on foreign oil for transportation. Both 
alternatives will likely be required to utilize coal to address energy 
security. The decision that determines which alternative is preferred 
may depend on whether, for a specific site and application, it is more 
cost effective to logistically transport liquid fuels or to transmit 
electric power from the gasification facility. It also depends on the 
ultimate transportation mode--for example, there are no current 
electric-powered commercial or military aircraft (except for small 
drones). From a greenhouse gas emissions standpoint, the less complex 
alternative may be to produce electric power coupled with CCS because 
it avoids the added complication of co-feeding biomass to achieve 
emissions reductions below that of conventional fuels production and 
use. But as mentioned above, both alternatives will be required to 
adequately address our overall energy security needs through 
utilization of coal.
      Responses of David Denton to Questions From Senator Domenici
    Question 9. How important is a secure domestic source of feed stock 
to the chemical industry in this country?
    Answer. If the chemical industry is to survive in this country, it 
must have a long-term secure source of low, and relatively stable, 
priced feedstocks and energy. Industrial gasification of domestic coal, 
petroleum residues (such as petcoke), biomass, and recycled secondary 
materials can help address this need. The run-up in energy prices, and 
the resultant volatility in energy prices, from natural gas and 
petroleum since the year 2000 has contributed to the loss of over 
100,000 jobs in the U.S. chemical industry alone (an overall job 
reduction of over 10% in that timeframe). Other energy-dependent 
industries, such as fertilizers, glass, steel, and forest products, 
have also been dramatically impacted. These high-technology and well-
paying jobs are being exported to other countries that have lower and 
more stable energy and feedstock costs.
    Question 10. The National Energy Technology Laboratory has 
indicated it is technologically and economically feasible to produce 
22,000 barrels of liquid naphtha (NAP-THA) per day and 27,800 barrels 
of diesel product per day from 24,500 tons of Illinois No. 6 coal while 
producing 124 mega-watts of electricity to the grid and capturing 
32,500 tons of carbon dioxide per day.
    Answer. It is certainly technically feasible to gasify coal and co-
produce diesel, naphtha, and electricity while capturing carbon 
dioxide. Economic feasibility depends on a number of factors, not the 
least of which are the competing price of conventional diesel fuel and 
the costs associated with capital project construction. Appropriate 
government incentives can be effective at reducing the impact or 
uncertainty of these economic variables.
    Question 11. Can you give us an estimate of the total domestic 
demand for naphtha from the chemical industry in this country?
    Answer. According to the DOE's Energy Information Administration, 
over 100 million barrels of naphtha were supplied for total U.S. 
petrochemical feedstock uses in 2006 (over 300,000 barrels of naphtha 
per day).
    Question 12. Assuming questions about further reducing carbon 
dioxide could be answered, at approximately what price per gallon would 
the naphtha have to be produced from a coalto-liquids process for the 
Chemical Industry to shift away from foreign natural gas or foreign 
LNG?
    Answer. The price would have to be sustained at some discounted 
level below the projected long-term market price of naphtha and/or the 
market-equivalent price for naphtha substitutes such as natural gas or 
LNG. It would also have to be at a price sufficient to enable the U.S. 
chemical industry to be competitive with global sources for the 
naphtha-derived end products. Naphtha prices (for petrochemical 
feedstock uses) typically track crude oil prices with about a 5% to 10% 
added cost (for example at an oil price of $40 per barrel, naphtha 
could be expected to have a market price of around $42 to $44 per 
barrel).
       Responses of David Denton to Questions From Senator Thomas
    Question 13. What specific technology gaps need to be closed by DOE 
and private industry working together to reduce the technical and 
economic risk of coal-derived fuel plants?
    Answer. The most important technology gaps are to demonstrate CTL 
technologies using actual U.S. coal-based syngas, to reduce the overall 
capital cost of CTL processes (including air separation, gasification, 
syngas cleanup, carbon capture, and any syngas-tofuels conversion 
technologies), and to improve the overall fuel yields of CTL processes.
    Question 14. In addition to financial incentives, in the form of 
tax credits, appropriations, and other tools at Congress' disposal, 
what regulatory approaches do you believe can be taken to advance the 
development of a domestic coal-derived fuel industry? Please address 
not only liability issues associated with carbon dioxide sequestration, 
but permitting of the actual plants, obstacles to construction of 
infrastructure, and other issues that you believe could be addressed 
from a regulatory, rather than a financial, standpoint.
    Answer. Regulatory incentives could include certification of CTL 
fuels, accelerated permitting of CTL plants, long-term liability for 
geologic storage of carbon dioxide, and requirements for utilization of 
CTL fuels in the transportation sector (civilian, military, and 
strategic petroleum reserves).
    Question 15. Does the use of a FT coal-derived diesel product have 
an improved footprint for nitrous oxide, particulate matter, sulfur 
dioxide, volatile organic compounds, and mercury over traditional 
sources of diesel? Please quantify the per gallon differences for 
criteria pollutant emissions that would result from consumption of a FT 
coal-derived diesel product versus traditional, petroleum-derived, 
diesel fuel.
    Answer. Fischer-Tropsch coal-derived diesel would be ultra-low in 
sulfur content and mercury and would bum cleaner than conventional 
diesel fuel (lower NOX, PM, etc.). The Department of Defense 
has compared emissions of F-T jet fuels versus conventional jet fuels. 
Similar improved emission results should be expected from F-T diesel 
fuels.
    Question 16. China is aggressively pursuing development of a CTL 
industry. If the U.S. does not, is it possible that we will be 
importing CTL fuels from China in the future?
    Answer. That is certainly a possibility, although current Chinese 
CTL production is targeted at satisfying their rapidly-growing domestic 
market.
    Question 17. What implications does this have for U.S. national 
security?
    Answer. Increasing reliance on foreign sources for our supplies of 
petroleum, natural gas (LNG), fuels, chemicals, fertilizers (i.e., 
food), and other industrial products has definite implications for our 
overall national security, including our energy security, food 
security, job security, and technological/industrial/manufacturing 
superiority. Without utilization of our abundant domestic resources, 
such as coal via gasification, all of these are at increased risk over 
the long-term.
    Question 18. We are told that Fischer-Tropes fuels require no 
modifications to existing diesel or jet engines, or delivery 
infrastructure including pipelines and fuel station pumps. Is that 
true?
    Answer. Eastman has not evaluated this issue sufficiently to 
comment. However, it is known that South Africa has successfully used 
F-T coal-derived fuel blends for over half a century to help address 
its transportation needs utilizing conventional engines and 
infrastructure.
                                 ______
                                 
   Responses of William Fulkerson to Questions From Senator Bingaman
    Question 1. The facilities that are commonly talked about here are 
very large and use significantly more coal than a comparable coal-fired 
power plant. If one were to blend in biomass on the levels you advocate 
how much biomass are we talking about for a typical plant? Is it 
realistic to assume enough could be produced in the area of the 
facility?
    Answer. This is a good question. Bob Williams and his colleagues at 
Princeton have made detailed calculations for a plant supplied by 
switchgrass and Illinois bituminous coal that uses oxygen blown 
gasification and captures and stores CO2 derived from both 
the switchgrass and the coal (CCS). The size of the plant they 
considered would supply 1030 MW of synthetic gasoline and diesel (about 
18,000 barrels per day of gasoline equivalent) plus 460 MW of electric 
power. These products would be manufactured from 2200 MW [7700 dry 
tonnes/day (dt/d)] of coal plus 900 MW (4500 dt/d) of switchgrass. To 
grow this much switchgrass would require about 500 square miles of land 
assuming a yield of 10 dry tonnes per hectare per year (t/ha/y) and an 
annual plant capacity factor of 80%. This would be 15% of the land 
within a 33-mile radius of the plant. As you can see building and 
operating such a plant would be no small undertaking, but the biomass 
growing and gathering effort would appear to be quite manageable.
    A key characteristic of this plant is that the net fuel-cycle-wide 
greenhouse gas emission rate associated with producing and consuming 
the synthetic liquid fuels would be about 27% of the rate for the 
petroleum-derived fuels displaced. In addition, the co-product 
electricity is produced in a high-efficiency combined cycle power plant 
at a carbon emission rate that is only about 10% of that for a new coal 
power plant that does not have CCS.
    Alternatively, Williams points out that mixed prairie grasses grown 
on carbon-deficient soil might be used as the biomass feedstock. In 
this case carbon is taken from the atmosphere both to grow the 
harvested prairie grass and to build up significant additional carbon 
in the soil and roots. (See Tilman, David, et al. Science, 314, 1598-
1600, December 8, 2006). Taking into account this extra sequestration 
Williams calculates that the amount of biomass required to reduce to 
zero the fuel cycle wide GHG emission rate associated with the 
production and consumption of the liquid fuels produced in such a plant 
would be about 3400 t/d requiring about 390 sq mi of land to grow. For 
such a plant the biomass and coal inputs account for 21% and 79% of 
fuel energy input, respectively. The energy and carbon flows for this 
system are shown in the attached figure.
    Williams' bio-coal system has the flexibility to accommodate a wide 
range of cellulosic feedstocks, including crop residues (e.g., corn 
stover and wheat straw) and forest product industry residues (e.g., 
logging residues) as well as dedicated energy crops.
    The coal gasifier and Fisher-Tropsch synthesis parts of the 
technology are fully commercial. The biomass technology is less well 
developed. Use of separate gasifiers for biomass and coal at the 
conversion plant may ultimately prove to be the least-costly approach; 
the needed large-scale biomass gasifiers for this approach are not yet 
commercial but could be commercialized by 2015 with a focused 
development effort. For the near term, some commercial coal gasifiers 
can be co-fired with modest amounts of biomass. In The Netherlands, the 
Nuon IGCC power plant at Buggenum has been fired for about a year with 
biomass accounting for 11% of the fuel energy input along with coal. 
Plans are to increase the percent of energy input from biomass to 20% 
during 2008.
    The biomass used in these systems will be much more costly than the 
coal (on a $ per million btu basis), and that will be good for the 
farmer. Nevertheless the calculations carried out by Williams and his 
colleagues show that if GHG emissions were valued or taxed at $25 to 
$30 per tonne of CO2 equivalent, these zero or near-zero GHG 
emitting Fisher-Tropsch liquids could be produced from coal + biomass 
with CCS at lower cost than Fischer-Tropsch liquids derived from only 
coal with either CO2 vented or with CCS. This remarkable 
economic finding arises from the huge credit realized from subsurface 
storage of photosynthetic CO2 that offsets the coal-derived 
carbon emissions from the plant and from combustion of the fuel 
products.
    An additional important benefit of this bio-coal fuels scheme is 
that more liquid fuel is produced per Btu of biomass than from the 
cellulosic ethanol process, for example--in fact, 2-3 times as much. 
This is due primarily to the fact that most of the energy to run bio-
coal plant comes from the coal. In the manufacture of cellulosic 
ethanol nearly all the energy to produce ethanol comes from the biomass 
and hence more biomass energy is required per Btu of fuel product. 
Since the limiting factor in the production of liquid fuels from 
biomass is the biomass resource, the comparatively high productivity of 
the bio-coal process is very important. Additionally less coal energy 
is used which reflects back into less mining and associated environment 
and safety impacts.
                               references
    Williams, Robert H., Eric D. Larson and Haiming Jin, ``Synthetic 
fuels in a world with high oil and carbon prices,'' 8th International 
Conference on Greenhouse Gas Control Technologies, Trondheim, Norway, 
19-22 June, 2006 and published in the Proceedings of the Conference.
    Williams, Robert H. (Princeton University), Stefano Consonni and 
Giulia Fiorese (Politecnico di Milano, Milan, Italy), and Eric Larson 
(Princeton University), ``Synthetic gasoline and diesel from coal and 
mixed prairie grasses for a carbon-constrained world,'' 6th Annual 
Conference on Carbon Capture and Sequestration, Pittsburgh, PA, 7-10 
May 2007, to be published in the Proceedings of the Conference.
    Responses of William Fulkerson to Questions From Senator Sanders
    Question 2. The Intergovernmental Panel on Climate Change has 
recently issued its Fourth Assessment Report Summary for Policy Makers. 
In that Report they concluded that the evidence that global warming is 
real and caused by humans is unequivocal. The MIT study, ``The Future 
of Coal,'' suggested that Carbon Capture and Storage (CCS) may increase 
the cost of electricity from coal by 20%, but an aggressive energy 
efficiency campaign could be conducted, so that less electricity is 
used, bringing our electricity bills down by 20% or more. What do you 
see as the cost of liquid fuel (diesel) and gaseous fuel from coal and/
or coal-biomass with CCS versus conventional diesel and natural gas in 
the near term and long term?
    Answer. Energy efficiency should be the first and foremost strategy 
pursued both for managing climate change and for reducing oil 
insecurity. I fully agree with the MIT report (MIT, 2007)\1\ on this 
point as well as the U.S. Climate Change Technology Strategic Plan and 
the IEA Energy Technology Perspectives of 2006. In addition the 
National Commission on Energy Policy Study points out the importance of 
efficiency in transportation for reducing oil dependence.
---------------------------------------------------------------------------
    \1\ Deutch, J., and E.J. Moniz et al., The Future of Coal: Options 
for a Carbon-Constrained World, an Interdisciplinary MIT Study, 2007.
---------------------------------------------------------------------------
    Regarding synthetic liquid fuels production, consider first a coal 
to liquids plant with full CCS (capturing 85-90% of the CO2 
not contained in the energy products). With this much CCS, the fuel 
cycle-wide GHG emission rate for the production and consumption of 
liquid fuel would be about the same as for the crude oil-derived 
products displaced. For these plants CO2 capture is 
relatively straightforward because most of the coal-derived carbon that 
is not contained in the produced synfuels is vented at the conversion 
facility as a relatively pure stream of CO2. As a result, 
the capture cost is very low--essentially the cost of drying and 
compressing CO2 to make it ready for delivery to an 
underground storage site. The cost of CO2 transport and 
storage would be comparably low if storage were in depleted oil or gas 
fields or in deep saline formations. If there were an opportunity to 
use the CO2 for enhanced oil recovery (EOR), the incremental 
cost for CCS could be negative--i.e., the value of the CO2 
for this purpose would often be more than the cost of capturing the 
CO2 and delivering it to the EOR site.
      (Note: A question that has arisen regarding CO2 EOR is 
whether the purchased CO2 actually stays put. It has been 
estimated that less than 1% of the CO2 purchased for 
CO2 EOR has escaped into the atmosphere (Stevens and Eppink, 
2001),\2\ but prior to the Beulah/Weyburn project [CO2 
produced at the Beulah ND Great Plains Synfuels Plant and piped 250 
miles north for EOR in the Weyburn oil field in Saskatchewan, Canada] 
emissions from CO2 EOR projects have not been routinely 
monitored. The Beulah/Weyburn project has been intensively monitored by 
a broad international scientific consortium, and no CO2 
emissions have been detected (IEA GHG R&D Programme, 2005).\3\ 
Moreover, modeling carried out for this project has estimated that over 
the next 5000 years less than 0.2% of the injected CO2 would 
escape to the biosphere.
---------------------------------------------------------------------------
    \2\ Stevens, S., and J. Eppink, CO2 Utilization for 
Enhanced Oil and Gas Production, Gasification Technologies 2001, San 
Francisco, 9 October 2001.
    \3\ IEA GHG R&D Programme, IEA GHG Weyburn CO2 
Monitoring & Storage Project, Petroleum Technology Research Centre of 
Canada, 2005.)
---------------------------------------------------------------------------
    Recent studies carried out by the National Energy Technology 
Laboratory (NETL) and Nexant researchers (Olson and Reed, 2007; Reed 
and Olson, 2007)\4\ analyzed a 50,000 barrels per day (2900 
MW1) synfuel plant producing a small amount of coproduct 
electricity (86 MWe). They found that with CO2 
vented such a plant could provide investors with a 20% rate of return 
on equity when the oil price is about $60 a barrel. They estimated that 
including CO2 capture would increase the capital cost by 
only about 2% and reduce the electricity output to 24 MWe. 
They estimated that capture and aquifer storage of the CO2 
would become cost completive with CO2 venting when the 
CO2 emissions value is of the order of $15 per tonne. Such a 
plant with CCS would produce liquid fuels with net carbon emission 
rates similar to that for the production and use of petroleum based 
fuels.
---------------------------------------------------------------------------
    \4\ S.C. Olson (Nexant) and M.E. Reed (NETL), ``Impacts of Future 
US GHG Regulatory Policies on Large-Scale Coal to Liquids Plants,'' 
paper presented at the 6th Annual Conference on Carbon Capture and 
Sequestration, Pittsburgh, PA, 7-10 May 2007, to be published in the 
Proceedings of the Conference.
    M.E. Reed (NETL) and S.C. Olson (Nexant), ``Technical, Cost, and 
Financial Impacts for Carbon Separation and Compression on Large-Scale 
Coal to Liquids Plants,'' presented at the 6th Annual Conference on 
Carbon Capture and Sequestration, Pittsburgh, PA, 7-10 May 2007, to be 
published in the Proceedings of the Conference.
---------------------------------------------------------------------------
    Carbon emissions can be further reduced to zero or near zero by 
coprocessing enough biomass with coal (as described in the answer to Q. 
1) and sequestering the CO2 produced. The sequestration of 
the carbon from the biomass offsets the coal-derived carbon emitted in 
the plant and from burning of the fuels produced. However, biomass is a 
more expensive feedstock than coal, so the cost of producing Fisher-
Tropsch liquid (FTL) fuels will be greater than for a straight FTL coal 
plant until the CO2 emissions value is sufficiently high. 
Williams and his colleagues at Princeton estimate that in the range of 
$25-30 per tonne of CO2 emissions value the bio-coal plant 
could provide synthetic fuels at lower net cost than for synfuels 
derived from coal only with CO2 vented or with 
CO2 captured and stored (see also the answer to Question No. 
1). This emissions value is in the ballpark estimated in the MIT coal 
study and many other studies as needed to begin to incentivize CCS from 
coal fired power plants. Without controlling emissions from coal fired 
power plants around the world mitigating climate change will be much 
more difficult, so a climate change policy should value CO2 
emissions at least this much.
    Question 3. I join Senator Murkowski in her concern about the need 
to retrofit our existing coal fired power plants to address the issue 
of carbon capture and storage. Some of the testimony suggested that 
adding ``oxyfuel'' to these older plants would be the best path to take 
as this burns pure oxygen, instead of outside air, producing a carbon 
dioxide-rich exhaust stream, with little or no NOX, so the 
CO2 is more concentrated and easier to capture for 
sequestration. Do you have any information on the ease/feasibility of 
retrofitting older coal plants or other coal-burning industrial 
facilities with ``oxyfuel''?
    Answer. I do not have the information you seek, but I do know an 
expert in the field who can probably answer this very interesting 
question. He is Ed Rubin of Carnegie Mellon University in Pittsburgh 
PA. I sent this information to Senator Markowski already.
    In general there are two approaches to reducing emissions of 
CO2 from existing coal fired power plants. The first is to 
scrub the stack flue gases to absorb the CO2 and sequester 
it. The second approach is to fire the power plant boilers with oxygen 
and coal to produce relatively pure CO2 flue gas without 
nitrogen, and then sequester it. Both of these approaches have been 
tried. They are not simple or inexpensive. If one is contemplating a 
new coal facility, the IGCC route with CCS will likely be the best 
approach depending on coal properties and special circumstances.
    The National Energy Technology Laboratory (NETL) has estimated that 
flue gas scrubbing will increase in the cost of electricity in the 
range of 45 to 70%. Advanced systems may bring this cost penalty down 
to about 20%. For the oxyfuel process the cost escalation is estimated 
to be 26 to 50% and with advanced systems in the range of 20%. The IGCC 
process with CCS would be in the range of 19 to 31% and with advanced 
systems in the range of 5-10%. The energy penalty is about 30% for a 
pulverized coal plant and 16% for an IGCC plant using current 
technologies.
    Responses of William Fulkerson to Questions From Senator Salazar
    Question 4. It appears from the written testimony, that liquid 
fuels produced from coal combined with biomass can result in lower 
greenhouse gas emissions than conventional gasoline. What are the 
technology hurdles to overcome in mixing biomass with coal to produce 
liquid fuels? Has the combination of biomass and coal been used at any 
commercial plant? What is a realistic % of greenhouse gas emissions 
compared to petroleum that we can expect to achieve.
    Answer. One hurdle involves the handling of various biomass 
feedstocks. These were addressed by Jay A. Ratafia-Brown of SAIC at the 
hearing. Jumping these hurdles will require some development work and 
first class engineering, as I understood Jay's comments. My impression 
from what Jay said was that there were no real showstoppers, however.
    Another hurdle involves biomass gasification. There are two 
alternative approaches to cofiring coal and biomass: one involves use 
of separate gasifiers to make the synthesis gas from which the liquid 
fuels are made, followed by a blending of the synthesis gas streams 
from coal and biomass for further processing. Alternatively, coal and a 
modest amount of biomass could be gasified in the same gasifier. Only 
the latter approach is viable with commercially available coal 
gasifiers, and co-gasification is much more difficult for some 
commercial coal gasifiers than for others.
    The 250 MWe IGCC plant at Buggenum in The Netherlands has been 
coprocessing 11% biomass and 89% coal (on an energy basis) for about a 
year, and plans are to increase the biomass percentage to 20% during 
2008. If that same gasifier fired with 11% biomass were used to make 
synthetic liquid fuels instead of electricity, the greenhouse gas (GHG) 
emission rate for the liquid fuels would be 20-25% less than the rate 
for the crude oil-derived hydrocarbon fuels displaced. This is an 
emissions rate that is similar to that from manufacturing corn ethanol. 
The co-gasification route uses cellulosic biomass instead of food 
biomass, thereby avoiding the corn, meat, and fertilizer price 
escalations that have accompanied the rush to ethanol.
    The coprocessing of cellulosic biomass with coal in this manner 
represents a much quicker route to establishing cellulosic biomass in 
the energy market than the cellulosic ethanol route, because, as 
remarked by Dan Reicher (former DOE Assistant Secretary for EE/RE): 
``Producing cellulosic ethanol is clearly more difficult than we 
thought in the 1990s'' (New York Times, 17 April 2007). Moving quickly 
to coal/biomass coprocessing would be very helpful in evolving a 
logistics infrastructure for cellulosic biomass.
    The separate gasifiers approach would make it feasible to increase 
the biomass fraction enough to reduce the net GHG emission rate to zero 
for liquid fuels. Realizing zero net emissions this way would require 
only \1/3\ to \1/2\ as many biomass Btus per Btu of liquid fuels as is 
required in making cellulosic ethanol. If there were a concerted 
development effort the separate gasifiers approach could likely be 
fully commercial by the middle of the next decade. This should in no 
way decrease our efforts to convert cellulose to ethanol or other fuels 
biochemically. Cellulosic ethanol has the advantage that no CCS is 
needed.
    Question 5. Even with the use of biomass, there are still 
substantial volumes of CO2 that must be captured and safely 
stored. Are there any recommendations this panel has on where to locate 
CTL facilities to facilitate the storage of CO2?
    Answer. Yes, in the biomass/coal plant considered by Williams and 
his colleagues some 4.5 to 5 million tonnes of CO2 would 
need to be stored each year. For the same amount of fuel produced 
changing the relative amounts of coal and biomass inputs doesn't affect 
very much the amount of CO2 that would be available for 
capture and storage, but adding more biomass makes the net carbon 
emissions to the atmosphere much less because the biomass-derived 
CO2 stored underground was taken out of the atmosphere in 
growing the biomass.
    Currently, DOE is conducting 7 regional assessments of 
sequestration opportunities. These cover the country. Good 
opportunities exist in many places, particularly where deep saline 
aquifers are available, and also in many regions where the 
CO2 can be used for enhanced oil recovery.
    As the MIT study emphasized, several storage projects storing at 
least a million tonnes of CO2 annually are needed to 
understand better the outlook for aquifer storage in different types of 
geological reservoirs and to provide a solid scientific and engineering 
basis for the CO2 storage regulatory regime for the longer 
term. CTL plants would be good candidate sources for providing the 
needed CO2 for some of these early storage projects, because 
the CO2 capture cost is low--much less than the cost for 
CO2 capture at power plants.
    The low CO2 capture cost at CTL plants also makes these 
attractive candidates for CO2 enhanced oil recovery 
projects.
    Siting bio-coal fuel plants requires access to adequate biomass and 
coal supplies as well as sequestration capacity. One possible site for 
a needed full-scale demonstration of bio-coal fuels production 
providing liquid fuels with zero or near-zero net lifecycle carbon 
emissions might be in southern Illinois, near the hypothetical site 
picked by Bob Williams for his recent study, because all the needed 
resources are there.
    A full-scale demonstration of a bio-coal fuels plant could be 
organized between the government and the private sector in the next 5-
10 years.
    Question 6. Can you discuss the water requirements for a CTL plant? 
Are there opportunities for reusing/recycling water in the process?
    Answer. No, I cannot answer this question, but as I recall, Jim 
Bartis from RAND at the hearing suggested about 7 gallons of water per 
gallon of fuel is in the right ballpark. Williams agrees with this 
rough estimate. Most of the water is for evaporative cooling; a minor 
fraction is consumed in the process.
    The availability of hydrological water supplies could be a 
constraint on the extent of deployment of synfuels technologies, 
especially in arid regions of the West. There evaporative cooling water 
requirements could be dramatically reduced shifting to dry cooling 
towers. Reducing process water requirements would be more challenging. 
But even in arid regions of the West there are substantial supplies of 
saline water deep underground--fossil water that is not involved in the 
hydrological cycle. Williams has estimated that the physical volume of 
process water required is comparable to the physical volume of 
CO2 that must be stored underground for synfuel plants that 
practice CCS. He has suggested investigation of the concept of 
recovering saline water and desalinating it for process use, and 
injecting for underground storage CO2 plus the salt-rich 
residual of the desalination process.
    Question 7. The auto industry has developed plug-in electric 
hybrids, and this committee has heard testimony about all-electric 
cars. Can you discuss the advantages and disadvantages of using coal to 
produce liquid fuels vs. using coal to generate electricity to charge 
batteries for electric cars and hybrids?
    Answer. It depends upon what you mean by plug-in hybrids. The 
problem is that we don't have a proper battery for such a vehicle. The 
energy density is too low by a factor of 2 to 3, and the battery life 
is too short under deep discharge conditions needed to maximize the 
usefulness of a plug-in hybrid. Great progress is being made, but 
batteries are not there yet. This is what I have been told by Venkat 
Shrinivasan of Lawrence Berkeley National Lab.
    When a proper battery becomes available using electricity to 
augment liquid fuels in transportation is a great idea. If off-peak 
power is used which is the logical strategy, the cost of electricity 
will be low. Also, because the efficiency of charging a battery is high 
as is the efficiency of electric drive electricity can be a very 
competitive energy source. Even with the current fraction of fossil 
derived electricity, use of the plug-in hybrid will probably reduce 
carbon emissions. Michael Kintner-Meyer of Pacific Northwest National 
Laboratory has estimated this.
    Nevertheless, one still needs fuels to run a hybrid and the bio-
coal fuels process provides a way to produce conventional liquid 
transportation fuels with zero or near zero net emissions from the 
whole fuel cycle.
    My conclusion is that we should work hard on better Li-ion 
batteries and bio-coal liquid fuels.
    Responses of William Fulkerson to Questions From Senator Thomas
    Question 8. You mention that coal and biomass gasification is a 
very promising technology that requires additional development, 
especially on biomass collection and preparation. What are the 
advantages that accompany waiting until this technology is commercial 
before imposing limits on the allowable carbon dioxide footprint?
    Answer. As I have already noted in my answer to question No. 4, one 
variant of the concept (based on co-gasification of modest amounts of 
biomass along with coal) can be introduced with current technology, 
whereas a system based on use of separate gasifiers needs further 
development.
    And as I have already noted, getting started via the co-
gasification route would be very helpful in evolving the logistics 
infrastructure for cellulosic biomass via learning by doing and in 
beginning a transition from food biomass (e.g., corn, soybeans) to 
cellulosic biomass in the production of liquid fuels.
    I will give you my opinion as to how public policy might be used to 
encourage both this early experience and a transition to more advanced 
technologies.
    As there are already technologies near-at-hand for reducing the 
carbon footprint of synfuels production and use, measures promoting 
deployment of reduced carbon technologies are needed. But in crafting a 
deployment policy, it would be wise to frame the policy so as to drive 
us toward mitigating climate change and reducing oil insecurity 
simultaneously without the government's attempting to pick 
technological winners.
    One approach to a policy for technology deployment would be to tax 
fuels on the basis of net carbon emissions (on a total fuel cycle 
basis). Obviously, such a carbon management policy would create a level 
playing field and would avoid the government pick winning problem. With 
such a policy, bio-coal fuel would be taxed much less than petroleum 
based fuels. A tax would give the consumer the right signals and 
industry as well. Most of the tax might be returned to the public to 
avoid hardships.
    California is trying a very interesting alternative approach. They 
will develop regulations requiring a gradual reduction in the carbon 
intensity of transportation fuels. This would penalize fuels from 
petroleum or coal without co-processing biomass and without 
sequestration. It would establish a strong market for low carbon and 
carbon neutral fuels such as the bio-coal fuel proposed by Williams (or 
cellulosic ethanol for example).
    Of course, a technology deployment policy, whatever its form, 
should be complemented by measures aimed at bringing to commercial 
readiness advanced concepts (e.g., bio-coal systems based on separate 
gasfiers for coal and biomass). So two parallel paths are needed in 
public policy.
    Question 9. In addition to financial incentives, in the form of tax 
credits, appropriations, and other tools at Congress' disposal, what 
regulatory approaches do you believe can be taken to advance the 
development of a domestic coal-derived fuel industry? Please address 
not only liability issues associated with carbon dioxide sequestration, 
but permitting of the actual plants, obstacles to construction of 
infrastructure, and other issues that you believe could be addressed 
from a regulatory, rather than a financial, standpoint.
    Answer. I am not an expert on this the topic of regulations. 
However, in answer to Q 8 a low carbon fuel standard is one regulation 
that should be explored carefully, and it is being considered seriously 
by California. With time a greater and greater fraction of fuel would 
be required to be low or no net carbon emitting fuel on a total fuel 
cycle basis. This could be formulated in a way that does not legislate 
technologies. Over time it would create a premium for such fuels that 
would feedback to creating supply options. Dr. Antonia Herzog of NRDC 
also suggested such a fuel standard at the hearing I believe.
    On the issue of liability associated with CO2 storage or 
transport I assume liability insurance should be required and that 
safety of pipelines and sequestration sites should be regulated by the 
states or the Federal government. Of course, pressurized CO2 
is commonly piped over considerable distances for enhanced oil recovery 
and the retention of the CO2 in those deposits appears good. 
See my response to question 2.
    In my judgment coal synfuels plants should not be built without the 
requirement that excess CO2 be captured and stored (CCS), 
and the bio-coal fuels process suggested by Williams with CCS is the 
best option suggested so far to tame the remaining evils of coal while 
optimizing the use of biomass.
    In my opinion if we want to reduce oil insecurity and also mitigate 
climate change a carefully conceived set of policies are needed some 
involving financial sticks and carrots and some involving regulatory 
tools. The six policies listed at the end of my testimony might be a 
good start, and I copy them here.
    First, the greenhouse gas emission externality must be reduced by 
putting a cost on emissions by cap and trade or tax or whatever. The 
Congress through various pieces of proposed legislation is actively 
considering this, and no doubt something will emerge.
    Second, a low-carbon fuel standard such as is being developed by 
the State of California should be adopted and existing subsidies on low 
carbon fuels should be discontinued.
    Third, regulations should be adopted to assure that no new coal 
synfuels plants are built without carbon capture and storage.
    Fourth, an oil security feebate might be enacted to put a floor on 
transportation fuel prices. If oil prices crash, say to $30/bbl from 
$60, transportation fuel could be taxed and part of the tax rebated to 
synfuels plants to help them compete and produce even with low world 
oil prices. Part of the tax revenues could be returned to the public.
    Fifth, regulations (such as improved CAFE standards) to promote 
more efficient use of transportation fuels need to be aggressively 
strengthened over time.
    Sixth, regulations and R&D to improve coal mine safety, worker 
health, and environmental improvement need to be periodically reviewed 
and upgraded if necessary.
    However, as I mentioned in my testimony it is relatively easy to 
make such a list. The hard work comes in sorting out the many options 
so policies invented are effective, fair, and politically possible. 
That is the difficult task facing this Committee and the Senate in the 
whole.
    Question 10. What specific technology gaps need to be closed by DOE 
and private industry working together to reduce the technical and 
economic risk of coal-derived fuel plants?
    Answer. The principal gap relates to CO2 storage. The 
extent to which CTL and coal in general have substantial futures in a 
carbon-constrained world depends critically on the future prospects for 
secure CO2 storage.
    We are not likely to be able to learn much more than we already 
know about this potential by doing more paper studies and small-scale 
experiments. Rather, a number of ``megascale'' projects (each storing a 
million tonnes of CO2 annually or more)\1\ in a variety of 
geological media, with an emphasis on deep saline formations, are 
needed as soon as possible both to understand the true practical 
potential for secure storage and to help define the regulatory regime 
needed for ``gigascale'' CO2 storage (MIT, 2007).
---------------------------------------------------------------------------
    \1\ For perspective, the CO2 storage rate for a 50,000 
barrels per day CTL plant would be 8 to 9 million tonnes per year.
---------------------------------------------------------------------------
    CO2 capture costs are much less for CTL plants than for 
coal power plants. The low cost of CO2 capture at CTL plants 
makes such plants strong candidates for providing low-cost 
CO2 for early megascale storage projects that can be very 
helpful in closing the gap. With regard to Williams' bio-coal fuels 
idea coal gasification and Fischer-Tropsch technologies are 
commercially ready. But there is much less experience with biomass. 
Large biomass gasifiers must be commercialized.
    Also, as I commented in the answer to Q 4 that development is 
needed in the preparation of biomass feedstocks of various sorts for 
the oxygen blown gasification step. Jay A. Ratafia-Brown of SAIC 
addressed these at the hearing.
    Question 11. Does the use of a FT coal-derived diesel product have 
an improved footprint for nitrous oxide, particulate matter, sulfur 
dioxide, volatile organic compounds, and mercury over traditional 
sources of diesel? Please quantify the per gallon differences for 
criteria pollutant emissions that would result from consumption of a FT 
coal-derived diesel product versus traditional, petroleum-derived, 
diesel fuel.
    Answer. Emissions of NOX, unburned hydrocarbons, and 
particulates from the burning of F-T diesel in compression ignition 
engines tend to be lower than from burning petroleum-derived diesel 
fuel (Norton et al, 1998).\2\ In addition, the S content of F-T fuels 
would be extremely low. This is because sulfur is a FT catalyst poison 
so it must be removed upstream of the FT units at the fuel processing 
plant.
---------------------------------------------------------------------------
    \2\ P. Norton, K. Vertin, B. Bailey, N.N. Clark, D.W. Lyons, S. 
Goguen, and J. Eberhardt, ``Emissions from Trucks Using Fischer-Tropsch 
Diesel Fuel,'' Society of Automotive Engineers Paper 982526, 1998.
---------------------------------------------------------------------------
    For coal-derived F-T liquids mercury would also have to be removed 
at the processing plant but it can be removed at very low incremental 
cost.
    The regulations developed or being developed for Diesel fueled 
vehicles including 18-wheelers should apply to FTL as to petroleum-
derived fuels.
    Question 12. China is aggressively pursuing development of a CTL 
industry. If the U.S. does not, is it possible that we will be 
importing CTL fuels from China in the future?
    Answer. Sure, it is possible that we will someday import CTL fuels 
from China. This is not likely to occur unless petroleum based fuels 
are more expensive. What we should be working to prevent is a CTL 
industry in China without capture and storage of the excess carbon. A 
U.S. low carbon fuel standard would provide an incentive for China to 
practice carbon capture and storage and bio-coal fuel production.
    Question 13. What implications does this have for U.S. national 
security?
    Answer. Coal synfuels are being advanced mainly because of energy 
supply insecurity concerns associated with dependence on oil imports 
and because of the prospect of sustained high oil prices. But whatever 
the U.S. does to enhance energy security by promoting CTL must be 
carried out in ways that simultaneously mitigate climate change. 
Because of the national security risks inherent in GHG emissions-
induced climate change, energy security concerns do not trump climate 
change concerns--as pointed out recently by a blue-ribbon panel of 
retired US admirals and generals from the Army, Navy, Air Force, and 
Marines (CNA, 2007).\3\
---------------------------------------------------------------------------
    \3\ CNA Corporation, National Security and the Threat of Climate 
Change, Alexandria, Virginia, 2007.
---------------------------------------------------------------------------
                                 ______
                                 
      Responses of James Bartis to Questions From Senator Bingaman
    Question 1. You advocate both for carbon capture and gasification 
of biomass with coal to meet greenhouse gas emissions targets. Using 
both together, you indicate there is a level where the total lifecycle 
emissions could theoretically be zero or even negative. Assuming that 
is with further technological development, what do you think are 
achievable standards today for percentage of carbon captured, biomass 
included, and lifecycle emissions?
    Answer. For first-of-a-kind CTL plants built in the United States, 
80 percent capture of all plant CO2 emissions is an 
achievable standard. This level of reduction should result in lifecycle 
emissions that are between 10 and 20 percent higher than motor fuels 
produced from conventional petroleum. This level of capture is 
consistent with the two lowest risk approaches for managing carbon in 
initial coal-based commercial plants, namely, co-firing of coal and 
biomass and the use of carbon dioxide for enhanced oil recovery. This 
emission factor is also appropriate for CTL plants that would capture 
carbon dioxide for use in a long-term demonstration of geologic 
sequestration.
    This percentage reduction is possible without forcing a CTL plant 
to incorporate gas turbines that can accept a fairly pure hydrogen 
feed. Adding such turbines would allow at least 95 percent removal; 
however, it is our judgment that requiring hydrogen turbines would add 
considerably to the market uncertainties associated with the future 
course of world oil prices and the technical uncertainties associated 
with building, operating, and capturing carbon from a first-of-a-kind 
plant.
    Question 2. You advocate that any facilities that receive federal 
incentives should be at least comparable in greenhouse gas emissions to 
petroleum-derived fuels. Our recent renewable fuels bill included a 
standard requiring fuels have 20% less lifecycle emission than the 
fuels they replace. How feasible would a similar standard be for coal-
derived fuels?
    Answer. Once initial production and carbon management experience is 
obtained, a similar, or even tighter standard, is feasible for fuels 
produced from a blend of coal and biomass. Such a standard is not 
feasible for the initial round of commercial plants because of the 
uncertainties discussed in the response to Question 1 above. Such a 
standard is also not feasible for plants that use only coal as a 
feedstock. The best that coal-only plants can achieve is parity with 
conventional petroleum-based fuels.
    This question raises a broader issue regarding implementing energy 
policy objectives, namely, the efficacy of emission standards for 
first-of-a-kind fuel plants that are subsidized by the government. The 
proposed legislation is not intended to obtain early production 
experience but rather to promote strategically significant amounts of 
production. But for coal-to-liquids, as well as biomass-derived fuels 
based on Fischer-Tropsch or cellulosic conversion, what is most needed 
is initial commercial production experience. For the case of coal-based 
plants, such initial experience should include attaining reasonably 
achievable levels of carbon management, as discussed in the response to 
Question 1. Setting standards for lifecycle CO2 emissions 
may be more appropriate once that initial experience is achieved.
      Responses of James Bartis to Questions From Senator Sanders
    Question 3. The Intergovernmental Panel on Climate Change has 
recently issued its Fourth Assessment Report Summary for Policy Makers. 
In that Report they concluded that the evidence that global warming is 
real and caused by humans is unequivocal. The MIT study, ``The Future 
of Coal,'' suggested that Carbon Capture and Storage (CCS) may increase 
the cost of electricity from coal by 20%, but an aggressive energy 
efficiency campaign could be conducted, so that less electricity is 
used, bringing our electricity bills down by 20% or more. What do you 
see as the cost of liquid fuel (diesel) and gaseous fuel from coal and/
or coal-biomass with CCS versus conventional diesel and natural gas in 
the near term and long term?
    Answer. I confine my answer to diesel from coal, since RAND does 
not yet have available useful estimates on the costs of diesel from 
coal-biomass. Also, our research has not addressed the production of 
natural gas from unconventional resources.
    As I testified, there are significant uncertainties regarding the 
costs of constructing and operating a first-of-a-kind coal-to-liquids 
production facility. There are also large uncertainties associated with 
the costs of developing and operating a facility for carbon 
sequestration. Using available design data, we estimate that the costs 
to produce a gallon of diesel from initial coal-to-liquid plants will 
be between $1.40 and $1.70 per gallon, assuming no carbon management. 
This is a plant gate cost, and should be compared to a refinery gate 
price, which for diesel is currently between $2.00 and $2.10 per 
gallon. Once the first commercial plants are operating and experience-
based learning begins to take place, costs should drop below $1.40 per 
gallon.
    With carbon capture and geologic sequestration, we estimate that 
the above cost range will increase to $1.60 to $2.10 per gallon. The 
broad range of all of our cost estimates reflects the fact that they 
are derived from highly conceptual engineering designs intended to 
provide only rough estimates of liquid fuel production costs and the 
cost uncertainties regarding geologic sequestration. We are also 
concerned that the recent large cost increases associated with the 
construction of major capital intensive projects are not adequately 
reflected in the above estimate. It is for these reasons that we 
recommended in our testimony that Congress consider cost-sharing 
options that would promote the development of a few site-specific 
designs that will provide reliable cost estimates.
    For some carbon management options, such as using carbon dioxide in 
enhanced oil recovery, the operators of coal-to-liquids plants may be 
able to sell their carbon at a price that recovers the extra costs 
associated with capturing, compressing and delivering it to the user's 
site. In this case, the costs of producing liquid fuels would be close 
to, or slightly lower than, the estimated costs without carbon 
management.
    The above ranges refer to production costs, including a reasonable 
return on investment. The actual prices will be based on future 
wholesale prices for diesel fuel (which is based on the world oil price 
and refining margins) and could be significantly lower or higher.
    Question 4. I join Senator Murkowski in her concern about the need 
to retrofit our existing coal fired power plants to address the issue 
of carbon capture and storage. Some of the testimony suggested that 
adding ``oxyfuel'' to these older plants would be the best path to take 
as this burns pure oxygen, instead of outside air, producing a carbon 
dioxide-rich exhaust stream, with little or no NOX, so the 
CO2 is more concentrated and easier to capture for 
sequestration. Do you have any information on the ease/feasibility of 
retrofitting older coal plants or other coal-burning industrial 
facilities with ``oxyfuel''?
    Answer. The feasibility of retrofitting older coal plants is an 
extremely important issue. Because RAND has not yet had the opportunity 
to investigate this problem, I am not able to provide you with an 
informed answer.
      Responses of James Bartis to Questions From Senator Salazar
    Question 5. It appears from the written testimony, that liquid 
fuels produced from coal combined with biomass can result in lower 
greenhouse gas emissions than conventional gasoline. What are the 
technology hurdles to overcome in mixing biomass with coal to produce 
liquid fuels? Has the combination of biomass and coal been used at any 
commercial plant? What is a realistic percentage of greenhouse gas 
emissions compared to petroleum that we can expect to achieve?
    Answer. The most efficient and economic gasifiers that are 
currently available for use in a Fischer-Tropsch system are entrained-
flow gasifiers. Such gasifiers operate at pressures of about 30 
atmospheres (450 pounds per square inch) and require a finely-sized 
feed, which is either blown or sprayed into the gasifier. The technical 
challenge is to devise the system that grinds, pressurizes, and feeds a 
stream of biomass or a combination of biomass and coal into the 
gasifier with high reliability and efficiency. This is a fairly minor 
technical challenge. It is an engineering problem focusing on 
performance and reliability, not a science problem. To establish the 
design basis for such a system requires the design, construction, and 
operation of one or a few test rigs. These test rigs need to be fairly 
large so that they are handling flows close to what would be the case 
in a commercial plant. This is because solids are involved and it is 
very difficult to predict performance and reliability of solids 
handling and processing systems when the size or throughput of the 
system undergoes a large increase. Such large-scale testing could be 
conducted during the design and construction of a full-scale plant for 
co-firing coal and biomass.
    Combinations of biomass and coal have been used in commercial 
plants in the past, but only at low biomass-to-coal ratios and with a 
limited number of biomass types. I believe the highest ratio used in 
continuous gasifier operations was at the Nuon IGCC power plant in The 
Netherlands, which was mentioned by Mr. Jay Ratafia-Brown in his 
testimony on May 24. This plant used a biomass-to-coal ratio (energy 
input basis) of about 1 to 5. Whereas much higher ratios, about 1 to 1, 
would be needed to bring carbon emissions to well-to-wheels parity with 
petroleum-derived fuels, assuming no carbon capture and sequestration. 
Additionally, the Nuon plant did not use the types of biomass that are 
estimated to be most abundant in the United States.
    The relative percent reduction of greenhouse gas emissions that can 
be achieved via combined biomass and coal use depends on the fraction 
of the feed that is biomass as compared to coal. Consider liquid fuel 
production plants without carbon capture and sequestration. At one 
extreme, imagine a plant that is fed only biomass. Greenhouse gas 
emissions are generated in cultivating, harvesting and transporting 
biomass, but these emissions are fairly small, so that using fuel from 
a biomass only plant would likely entail lifecycle greenhouse gas 
emissions that are less than 10 percent of those from conventional 
petroleum-based fuels. As we add coal to the plant, the lifecycle 
greenhouse gas emissions increase. At a 50-50 mix, the emissions levels 
would be comparable to conventional petroleum, and would increase to 
about 2.0 to 2.3 times conventional petroleum for plants using just 
coal.
    The preceding discussion applies to liquid fuel production plants 
without carbon capture and sequestration. With carbon capture and 
sequestration, a 50-50 mix of biomass and coal should yield lifecycle 
greenhouse gas emissions that are close to zero. As the biomass ratio 
increases, the lifecycle emissions would become negative, and as the 
coal ratio increases, net emissions would increase until they reached a 
maximum that would be very close to that associated with conventional 
petroleum.
    Question 6. Even with the use of biomass, there are still 
substantial volumes of CO2 that must be captured and safely 
stored. Are there any recommendations this panel has on where to locate 
CTL facilities to facilitate the storage of CO2?
    Answer. RAND has not conducted research on the geologic and 
technical issues associated with site selection of facilities for the 
storage of CO2, and therefore cannot provide an informed 
response to the main thrust of this question. We strongly recommend 
that the U.S. government take measures as soon as possible that are 
required to conduct multiple large-scale demonstrations of geologic 
sequestration at various sites across the United States. In addition to 
geologic and technical issues, the site selection process should 
consider proximity to major coal resources. We also recommend that the 
site selection process should promote extensive public participation, 
including inputs from state and local governments, industry, and non-
governmental organizations.
    Question 7. Can you discuss the water requirements for a CTL plant? 
Are there opportunities for reusing/recycling water in the process?
    Answer. RAND has conducted research on water consumption and 
production in Fischer-Tropsch plants that use natural gas as a 
feedstock to produce liquid fuels. Based on this research, we estimate 
that at least 1.5 barrels of water would be consumed in a CTL plant for 
each barrel of liquid product produced. By consumed, we mean water 
either used to make hydrogen or lost through evaporation. We assume 
that no once-through cooling water is used. To obtain the minimum water 
usage, the plant would need to install dry cooling towers and 
incorporate extensive measures to minimize water losses in the power 
generation and oxygen production portions of the plant. The net result 
of designing such a plant would be an increase in investment costs and 
a reduction in the operating efficiency of the plant. As a result, such 
a plant would only be built in areas in which water, including suitable 
groundwater, was in very limited supply.
    In areas in which water is abundant, we anticipate that as much as 
10 barrels of water would be consumed in a CTL plant for each barrel of 
liquid product produced. Such a plant would likely use less expensive 
evaporative cooling towers. The change from dry cooling towers to 
evaporative cooling accounts for most of the additional water losses. 
The remaining losses are associated with less recycling of process 
water.
    For most CTL plants, the water consumption will fall between 1.5 
and 7 barrels of water per barrel of liquid product produced, with the 
actual amount depending on the cost, availability, and quality of local 
water supplies.
    Question 8. The auto industry has developed plug-in electric 
hybrids, and this committee has heard testimony about all-electric 
cars. Can you discuss the advantages and disadvantages of using coal to 
produce liquid fuels vs. using coal to generate electricity to charge 
batteries for electric cars and hybrids?
    Answer. With progress in technology, electric vehicles and plug-in 
hybrids could be cost effective as alternatives to conventional fuels 
and a means of reducing greenhouse gas emissions. At present, however, 
the status of battery technology is such that all-electric cars are 
expensive and limited in acceleration and range, and therefore have a 
very limited market in the United States. Likewise, shortfalls in 
current battery technology limit the ability of plug-in hybrids to 
offer significant fuel savings at reasonable costs, especially compared 
to current and emerging non-plug-in hybrids.
    If the battery problems can be overcome, the extent to which 
greenhouse gas emissions would be reduced would still depend on the 
CO2 emissions associated with producing the electricity used 
to charge the batteries. If the electricity is produced from fossil 
fuels, these emissions could be mitigated with carbon capture and 
sequestration.
    Whether and when sufficient progress in battery technology will 
occur remains an open question. As such, electric cars and plug-in 
hybrids, as well as hydrogen-powered vehicles, are research concepts 
that are deserving of federal support. However, it would be imprudent 
to delay measures to address global climate change or energy security 
based on the prospect that any of the advanced concepts are the 
``silver bullet.''
       Responses of James Bartis to Questions From Senator Thomas
    Question 9. In terms of emissions, your testimony focuses on 
greenhouse gases. There are many other substances, however, that 
Congress has deemed appropriate to regulate and reduce. They include 
mercury, sulfur dioxide, nitrous oxide, particulate matter, and others.
    Answer. None received.
    Question 10. How do coal-derived fuels perform in these categories 
relative to the conventional fuels that they will replace?
    Answer. This answer address emissions that would occur at the plant 
site at which coal-derived liquids would be produced. The answer to 
Question 11 addresses emissions from the use of the fuel.
    The front end of an F-T coal-to-liquid fuel production plant is 
very similar to power plants that would be based on coal gasification. 
The primary difference is that the F-T catalysis reactor is extremely 
sensitive to trace amounts of mercury and sulfur, so that extensive 
removal of compounds containing these elements will occur before the 
synthesis gas is allowed to enter the F-T reactor.
    For mercury, we anticipate that commercially available mercury 
control systems can capture between 90 and 95 percent of the mercury 
that would otherwise enter the F-T reactor. This would reduce net plant 
mercury emissions to between 5 and 10 percent of the level that would 
result if the same amount of coal were burned in a conventional power 
plant.
    For sulfur, commercially available removal systems are able to 
reduce sulfur concentrations to parts per billion. Net emissions of all 
gaseous sulfur compounds to the atmosphere would be negligible, namely, 
well under a hundredth of what would be released by a modern power 
plant meeting current standards and burning the same amount of coal.
    With regard to particulate emissions, these would come from various 
sources within a CTL plant. Without recourse to a front-end engineering 
design, we are unable to provide a numerical estimate. However, it is 
our judgment that, given the performance of commercially available 
equipment for controlling emissions, particulate emission levels are 
unlikely to be a deciding factor on the ability to site a CTL plant.
    The only significant sources of nitrogen oxide emissions are the 
gas turbines used to produce power used within the CTL plant and for 
sale. The amount of fuel consumed by the gas turbines can vary 
significantly based on how the CTL plant is designed. A reasonable 
range for a CTL plant is that 70 to 150 MW of gas turbine capacity will 
be in operation for each 10,000 barrels per day of liquids production 
capacity. Nitrogen oxide emissions from these units should be 
comparable to the state of the art for turbines designed for combined-
cycle power plants designed for natural gas or coal.
    Question 11. Specifically, does the use of F-T coal-derived diesel 
products have an improved footprint for nitrous oxide, particulate 
matter, sulfur dioxide, volatile organic compounds, and mercury over 
traditional sources of diesel? Please quantify the per gallon 
differences for criteria pollutant emissions that would result from 
consumption of F-T coal-derived diesel products versus traditional, 
petroleum-derived, diesel fuel. China is aggressively pursuing 
development of a CTL industry. If the U.S. does not, is it possible 
that we will be importing CTL fuels from China in the future? What 
implications does this have for U.S. national security?
    Answer. Published test data indicate that using F-T-derived diesel 
fuel in existing heavy and light duty diesel engines yields reduced 
emissions of nitrogen oxides, particulate matter, sulfur oxides, and 
volatile organic compounds as compared to ultra-low sulfur diesel fuel 
derived from petroleum. Reported reductions are generally in the range 
of 15 percent for nitrogen oxides and between 25 to 50 percent for 
particulate matter. Somewhat greater levels of nitrogen oxide and 
particulate matter reductions are possible in engines modified or 
specifically designed for F-T fuel use. While F-T fuel has less than a 
tenth of the sulfur of the typical ultra-low sulfur diesel fuel 
currently being sold, we do not anticipate a full ten-fold or greater 
reduction in sulfur oxide emissions, since other sources of sulfur, 
such as lubricating oil, become noticeable contributors at these very 
low levels. We are still evaluating the literature results for volatile 
organic compounds and carbon monoxide. The results that we have already 
seen indicate no significant changes. Vehicular fuel use, including 
gasoline and diesel, is not viewed as an important source of mercury 
emissions.
    Both the national security and economic interests of the United 
States would benefit from China's development of a CTL production 
capability. By using China's coal resources to produce CTL, China will 
need to import less fuel from the Middle East. This should lead to 
lower world oil prices and thereby, savings to all oil users, including 
American users, and lower export revenues to OPEC members, a number of 
whom are governed by regimes that do not support American foreign 
policy objectives.
    It is highly unlikely that China will export CTL fuels since even a 
very large CTL industry in China is unlikely to be able to meet the 
shortfall between China's domestic production of crude oil and its 
demand for liquid fuels.
    Question 12. CTL fuels are the only currently available ``drop in'' 
replacements for military and civilian aviation fuel. Civilian aircraft 
flying in and out of Johannesburg, South Africa have been using CTL 
fuels for years. What specific actions do you believe Congress can and 
should take to facilitate development of a U.S. CTL industry to assist 
the U.S. aviation industry?
    Answer. RAND research shows that the benefits of developing a CTL 
industry in the United States do not accrue to any specific types of 
fuel users, but rather to all fuel users, including military and civil 
aviation. This is because the main benefit of producing any 
unconventional fuel is that it reduces demand for conventional 
petroleum and thereby reduces world oil prices.
    Coal-derived liquids have certain performance properties that allow 
them to command a premium price in certain markets. In particular, 
because CTL fuels are nearly free of sulfur and have a very high cetane 
number, CTL fuels will command a premium when used as automotive and 
truck fuels. But these two characteristics offer less value when 
considering aircraft applications. As such, we believe that commercial 
aircraft are not a likely market for CTL fuels produced in the United 
States over the foreseeable future.
    Our finding is that any federal actions to promote CTL use in 
commercial aircraft would not be productive. The critical path for CTL 
development is obtaining initial commercial operating experience and 
use in automotive applications.
    Question 13. Mr. Fulkerson testified that ``If the excess 
CO2 produced is sequestered instead of vented then the coal 
synfuels process can be equivalent to petroleum in net CO2 
emissions.'' Ms. Herzog's testimony seems to dispute this. How do we 
reconcile these differences of opinion?
    Answer. At RAND, we have conducted extensive research on this 
topic. Our analyses show that net CO2 emissions from CTL 
plants with sequestration range from slightly less than to slightly 
more than petroleum. What drives the differences in our calculations 
are assumptions regarding the degree of carbon capture (the last few 
percent of removal costs much more than the first 95 percent on a $ per 
pound basis), the efficiency of the CTL plant, and the emissions 
associated with the refining of conventional petroleum. Additionally, 
most CTL plants co-generate electric power. This electric power will 
displace a conventional power plant. Assumptions regarding whether the 
displaced power would be from an uncontrolled coal-fired power plant or 
from a plant using carbon capture and sequestration also influence how 
CTL emissions are calculated.
    Question 14. In addition to financial incentives, in the form of 
tax credits, appropriations, and other tools at Congress' disposal, 
what regulatory approaches do you believe can be taken to advance the 
development of a domestic coal-derived fuel industry? Please address 
not only liability issues associated with carbon dioxide sequestration, 
but permitting of the actual plants, obstacles to construction of 
infrastructure, and other issues that you believe could be addressed 
from a regulatory, rather than a financial, standpoint.
    Answer. A great deal of research suggests that the most cost-
effective approach for addressing both energy security and greenhouse 
gas reduction is through a broadly applied market-based approach that 
stimulates changes in energy production and consumption through 
increases in the costs of using petroleum-derived energy and through 
increases in the costs of energy uses according to their greenhouse gas 
emissions. An example of this approach would be an energy security tax 
on all petroleum-derived liquid fuels and a tax on all fossil energy 
fuels based on their net greenhouse gas emissions, taking into account 
any reductions in emissions from sequestration. This approach would 
help to level the playing field among different energy forms based on 
their potential energy security and greenhouse gas impacts. Under this 
approach, a domestic coal-derived (or coal and biomass-derived) fuel 
industry would develop to the extent that such a fuel lifecycle was 
economically advantageous over other options, taking into account the 
security and greenhouse gas taxes.
    Before this or any other approach based on financial incentives can 
be effectively applied, however, we believe that the government needs 
to support early, but limited commercial operating experience for coal-
based liquids production so that both industry and government are 
better prepared to act wisely as further information becomes available 
regarding world oil prices, the viability of carbon capture and 
sequestration, and the future requirements associated with addressing 
energy security and greenhouse gas emissions. The approach we are 
recommending is somewhat akin to insurance, or paying for an option to 
make a future investment even if it is decided later that the 
investment is not needed. For this measured approach, we see a need for 
financial incentives, but we see no need, at this time, for special 
legislation or regulatory actions to accelerate permitting or to 
address obstacles to construction of infrastructure.
    I am unable to provide an informed comment on the regulatory issues 
associated with siting and operating carbon dioxide sequestration 
facilities, since neither I nor others at RAND have conducted 
sufficient research on this topic.
    Question 15. What specific technology gaps need to be closed by DOE 
and private industry working together to reduce the technical and 
economic risk of coal-derived fuel plants?
    Answer. In my testimony, I listed four important measures that the 
federal government can take, in cooperation with industry, to reduce 
the uncertainties in the costs and performance of coal-derived fuel 
plants. The first of these measures is to cost-share in the development 
of a few site-specific front-end engineering designs of commercial 
plants based on coal or a combination of coal and biomass. The second 
is to foster early commercial experience by firms with the technical, 
financial, and management wherewithal to successfully bring a project 
to fruition and most importantly to capture and exploit the learning 
that will accompany actual operations. The third of these measures is 
to conduct multiple demonstrations and, by way of such demonstrations, 
develop the regulatory framework required for a commercial 
sequestration industry. And the fourth of these measures is to support 
research, development, testing and evaluation of concepts for 
integrating coal and biomass for the production of liquid fuels. An 
early low-risk, high-payoff opportunity in this last area is the 
construction and operation of test rigs and/or pilot plants for 
evaluating the performance subsystems for co-feeding coal and biomass 
into entrained-flow gasifiers.
    Question 16. I have been told that coal-derived fuels have a higher 
cetane level. Please explain the benefits, environmental and otherwise, 
that are to be derived from that fact.
    Answer. The cetane number is a measure of how readily diesel fuel 
ignites. The higher the cetane number, the sooner a fuel will start to 
burn after it is injected into the combustion chamber. Coal-derived 
fuels from the Fischer-Tropsch process will generally have a cetane 
number from 70 to 80. This is significantly higher than refinery 
diesel, which generally ranges from 40 to 55.
    In general, fuels with higher cetane numbers make starting a cold 
engine easier and reduce hydrocarbon and soot pollutants generated in 
the minute or so following a cold start. Higher cetane number fuels 
also tend to reduce NOX and particulate emissions, although 
the amount of such reductions is dependent on engine design.
    Fuels with high cetane numbers are generally lower in aromatics. 
Coal-derived fuels based on the Fischer-Tropsch method have extremely 
low levels of sulfur and aromatics and these two attributes offer 
improved environmental performance with regard to both particulate and 
hydrocarbon emissions and should extend the operating life of catalytic 
converters used to remove pollutants from diesel exhaust.
    Question 17. We are told that Fischer-Tropsch fuels require no 
modifications to existing diesel or jet engines, or delivery 
infrastructure including pipelines and fuel station pumps. Is that 
true?
    Answer. This is true, so long as additives are allowed. In general, 
the additive package would be similar to that associated with 
conventional fuels intended for use in diesel or jet engines. For 
unblended (i.e., 100 percent Fischer-Tropsch liquids) coal-derived 
fuels, additional additives may be required to assure adequate 
lubricity and to protect seals.
                                 ______
                                 
     Responses of Antonia Herzog to Questions From Senator Sanders
    Question 1. I am very supportive of your suggestion that we can 
better power our vehicles with electricity, whether generated by coal 
or renewable electricity like solar and wind, rather than converting 
the coal to liquids and using that liquid fuel in our internal 
combustion engines, which are much less efficient than electric motors. 
You pointed out that plug-in hybrid electric vehicles (PHEVs) powered 
by coal-based electricity with CCS are about 10 times better than Coal 
To Liquids (CTL) with CCS used in a regular hybrid vehicle when it 
comes to CO2 emissions. You also concluded that PHEVs using 
coal-electricity with CCS are twice as good as Coal to Liquids with CCS 
in terms of oil displaced, that is, I presume the same as the amount of 
distance that can be traveled with the same ton of coal. These are 
important findings. Can you please share with us the underlying 
assumptions for those calculations? Your suggestion that the PHEV will 
travel 3.14 miles/kwh, for example, is based on what tests or studies? 
Some have suggested that PHEVs can do even better by going 5 or 6 
miles/kwh.
    Answer. Attached is a spreadsheet with the basic calculations 
behind these results.*
---------------------------------------------------------------------------
    * Information has been retained in committee files.
---------------------------------------------------------------------------
    As you noted, our conclusion is that a ton of coal used in a power 
plant employing carbon capture and storage (CCS) to generate 
electricity for a plug in hybrid vehicle will displace more than twice 
as much oil and emit one-tenth as much CO2 per mile driven 
as using the same coal to make liquid fuels in a plant that uses CCS.
    The analysis used the vehicle efficiency assumptions (37.1 miles/
gal, 3.14 miles/kWh) are from the just released EPRI-NRDC Joint 
technical Report, Environmental Assessment of Plug-in Hybrid Electric 
Vehicles, Volume 1: Nationwide Greenhouse Gas Emissions (1015325), July 
2007. See the report for a more detailed discussion of the analysis 
(http://www.epri-reports.org/ and http://www.epri-reports.org/
Volume1R2.pdf).
    One assumption in our spreadsheet that is not quite consistent with 
the EPRI modeling is the assumption that PHEVs operate on electricity 
75% of the time. We believe the number is probably closer to 50%.
    Question 2. I understand that PHEVs at the efficiency you suggest 
would use 10 kwhs to go 31.4 miles or, at 10 cents per kwh, about a 
dollar for 31 miles, versus what a gasoline car would pay for 31 miles 
of travel, over $3. Is that accurate? If PHEVs are charged at cheaper 
night-time rates, what is the cost equivalent per gallon of fuel? I 
have heard that it is less than one dollar per gallon. If we consider 
that PHEVs will most likely be charged by a mix of fuels that are 
cleaner than coal, like natural gas, hydro, and others, what is the 
CO2 comparison today, without CCS with a PHEV to a regular 
hybrid fueled by CTL fuel without CCS? Do your figures consider the 
total life cycle CO2 emissions, that is, do they include 
energy costs from transportation, storage, pumping of the liquid fuels 
and other energy costs in the CTL numbers?
    Answer. The calculation you present is correct. Again I refer you 
to the joint NRDC-EPRI study (http://www.epri-reports.org/
Volume1R2.pdf) mentioned in Q1 for a detailed discussion of the full 
lifecycle (well-to-wheels) GHG emissions for PHEV for different mix of 
fuels (Figure 5-1). There is also NRDC's plug-in hybrid factsheet which 
can be found at, http://www.nrdc.org/energy/plugin.pdf.
    For PHEVs, per mile global warming emissions are greatly affected 
by what is used to charge them. Today's typical pulverized coal plant 
(2.5 pounds CO2e/kWh) results in the highest emissions, 
about 7.25 lbsCO2e/mi. The average grid (1.3 pounds 
CO2e/kWh) is a mix of generation sources mainly coal, 
natural gas, nuclear and large hydro resulting in about 5.5 
lbsCO2e/mi. Non-emitting renewable electricity sources such 
as wind, geothermal, and solar provide the lowest emissions per mile, 
about 3.5 lbsCO2e/mi. This analysis assumes all vehicles 
travel 12,000 miles per year. On-road efficiency for conventional 
vehicles is 24.6 miles per gallon while hybrid drivetrains achieve 37.9 
mpg on gasoline. PHEV electrical efficiency is 3.2 mi/kWh and 49% of 
the PHEV miles are using stored grid energy. Much of the PHEV charging 
occurs during the night (see Figure 4-5).
    Question 3. The Intergovernmental Panel on Climate Change has 
recently issued its Fourth Assessment Report Summary for Policy Makers. 
In that Report they concluded that the evidence that global warming is 
real and caused by humans is unequivocal. The MIT study, ``The Future 
of Coal,'' suggested that Carbon Capture and Storage (CCS) may increase 
the cost of electricity from coal by 20%, but an aggressive energy 
efficiency campaign could be conducted, so that less electricity is 
used, bringing our electricity bills down by 20% or more. What do you 
see as the cost of liquid fuel (diesel) and gaseous fuel from coal and/
or coal-biomass with CCS versus conventional diesel and natural gas in 
the near term and long term?
    Answer. The MIT report estimates the costs of Fischer-Tropsch 
liquid fuel and synthetic natural gas from coal with and without CCS, 
see p. 156-157, Table A-3.F.2. They estimate that the F-T fuel 
production cost is $50/bbl without CCS and $55/bbl with CCS. The 
production cost of SNG is estimated to be $6.7/million BTU without CCS 
and $7.5/million Btu with CCS. We believe these estimate are on the low 
end. Furthermore, an economic study by Jim Dooley of Battelle (Jim 
Dooley, Robert Dahowski, Marshall Wise, Casie Davidson ``Coal-to-
Liquids and Advanced Low-Emissions Coal-fired Electricity Generation,'' 
presentation at NETL conference, May 9, 2007, PNWD-SA-7804) predicts 
that in a carbon constrained world CTL would not be a competitive fuel 
even with CCS.
    Question 4. I join Senator Murkowski in her concern about the need 
to retrofit our existing coal fired Power plants to address the issue 
of carbon capture and storage. Some of the testimony suggested that 
adding ``oxyfuel'' to these older plants would be the best path to take 
as this burns pure oxygen, instead of outside air, producing a carbon 
dioxide-rich exhaust stream, with little or no NOX, so the 
CO2 is more concentrated and easier to capture for 
sequestration. Do you have any information on the ease/feasibility of 
retrofitting older coal plants or other coal-burning industrial 
facilities with ``oxyfuel''?
    Answer. Combustion with pure oxygen instead of air eliminates the 
nitrogen, avoids production of nitrogen oxides during combustion, and 
produces an exhaust gas with a very high CO2 concentration, 
making it easy to capture through simple compression and cooling. The 
main operating cost of this system comes from the operation of the air 
separation unit. Oxy-fuel PC combustion is in early commercial 
development but appears to have considerable potential. It is under 
active pilot-scale development, and larger projects are under 
consideration, with a decision pending by the board of Saskpower at the 
end of July whether to proceed with a 300MW unit.
    Currently, an oxyfuel retrofit seems to be a more economically 
attractive option than a retrofit with post-combustion capture system 
(e.g. amine scrubbing). The recent MIT study on the Future of Coal 
confirmed this point (p. 148). It is possible, however, that in a 
decade or two a more attractive option through post-combustion capture 
might exist, although there is no guarantee. It is at least as likely 
that oxyfuel will be the retrofit technology of choice, or that there 
will be no unanimous choice and that the optimum choice will depend on 
the specifics of a particular plant.
    The study also stated clearly that ``retrofitting an existing coal-
fired plant originally designed to operate without carbon capture will 
require major technical modification'' (p. xiv). Moreover, no such 
retrofits have been performed. Constructing a new plant with capture 
from the outset makes engineering and economic sense, and we should 
minimize our reliance on retrofits as much as possible by designing and 
building all new plants with capture.
     Responses of Antonia Herzog to Questions From Senator Salazar
    Question 5. It appears from the written testimony, that liquid 
fuels produced from coal combined with biomass can result in lower 
greenhouse gas emissions than conventional gasoline. What are the 
technology hurdles to overcome in mixing biomass with coal to produce 
liquid fuels? Has the combination of biomass and coal been used at any 
commercial plant? What is a realistic percentage of greenhouse gas 
emissions compared to petroleum that we can expect to achieve?
    Answer. Two key technical hurdles to overcome in cogasifying 
biomass with coal are the biomass feedstock handling system, biomass 
comes in many shapes and sizes, the moisture content of the biomass, 
and impurities mixed in with the biomass. There is only one commercial 
scale co-gasification of biomass with coal that is in currently in 
operation worldwide. It is 253 MWe Nuon IGCC power plant in Buggenum, 
The Netherlands. However, it produces electricity and not Fischer-
Tropsch liquids.
    We believe that if we are going to start producing a new type of 
transportation fuel to replace petroleum-based fuels then the 
production of the new fuel must be consistent with our need to 
significantly reduce our global warming emissions starting today and 
for the long term. Therefore, the new fuel must produce well-to-wheels 
lifecycle greenhouse gas emissions significantly below that of 
conventional gasoline or diesel fuels, at least 20 percent lower. It is 
technically possible to produce a coal derived liquid fuel with 
greenhouse gas emissions at this level or lower. Modeling performed by 
Bob Williams from Princeton University indicates that reducing the fuel 
cycle-wide GHG emission rate 30% relative to that for the crude oil-
derived hydrocarbon fuels displaced would require that biomass (in this 
case switchgrass) accounts for 14% of the fuel input. And achievement 
of this emission rate would also require storing underground 85% of the 
coal carbon not contained in the products along with 90% of the carbon 
in the biomass (R. Williams, ``Synthetic fuels in a world with high oil 
and carbon prices'', International Conference on Greenhouse Gas Control 
Technologies, Trondheim, Norway, 19-22 June 2006).
    Question 6. Even with the use of biomass, there are still 
substantial volumes of CO2 that must be captured and safely 
stored. Are there any recommendations this panel has on where to locate 
CTL facilities to facilitate the storage of CO2?
    Answer. This is correct. As a result it would be most cost-
effective to locate a CTL facility as near as possible to a deep 
geologic formation into which the CO2 can be permanently disposed such 
as a deep saline aquifer.
    Question 7. Can you discuss the water requirements for a CTL plant? 
Are there opportunities for reusing/recycling water in the process?
    Answer. CTL production is expected to require large quantities of 
water, 5-7 gallons of water for every gallon of CTL product (see http:/
/www.netl.doe.gov/technologies/oil-gas/publications/AP/
IssuesforFEandWater.pdf).

            Water Requirements for Liquefaction Technologies
          There are three major requirements for water in a typically 
        sized 50,000 barrels per steam day (BPSD) liquefaction plant:

                    Process Water. Process water is water that 
                is intimately involved in the liquefaction process and 
                sometimes even plays a part in chemical reactions. 
                Examples include water in coal gasifiers that reacts 
                with carbon to form CO and hydrogen and water in water-
                gas-shift reactors. Process water may also be used in 
                scrubbers for the purpose of removing ammonia and 
                hydrogen chloride from syngas. Some process water is 
                consumed in the liquefaction process and must be 
                replaced with additional makeup water. It can also be 
                lost through evaporation into process gas streams or in 
                waste slurry streams, such as flue gas desulfurization 
                sludge or gasifier slag.
                    Boiler Feed Water. Boiler feed water is 
                used to produce steam. Much of this water is recovered 
                as condensate and returned to the boiler, but there is 
                some loss due to leakage and the occasional need for a 
                blowdown to purge impurities from the system. Also, 
                steam may need to be injected at a specific step in the 
                process, in which case the boiler feed water is 
                converted to process water.
                    Cooling Water. Chemical plants, refineries, 
                power plants, etc., often require cooling of process 
                streams, and a CTL plant is no different in this 
                regard. Such cooling is typically accomplished using 
                circulating water. After absorbing heat, the cooling 
                water is sent to a cooling tower, where evaporation of 
                part of the water cools the remaining portion so that 
                it can be recirculated. Typically, cooling water loss 
                through evaporation in the tower is the most 
                significant factor in total overall water consumption.

          The amount of water required to operate a coal liquefaction 
        plant is a function of many variables, including the design of 
        the liquefaction unit, the type of gasifier used to provide the 
        syngas or hydrogen, the coal properties, and the average 
        ambient temperature and humidity. In the 1990s, Bechtel 
        performed a series of studies for DOE in which they evaluated a 
        variety of coal liquefaction schemes for indirect liquefaction 
        (Bechtel 1998) and determined the following water needs:

                  For eastern coal 7.3 gal of water/gal F-T liquid
                  For western coal 5.0 gal of water/gal F-T liquid

          The above differences in water requirements between eastern 
        and western coals probably reflect the higher moisture content 
        of western coal and lower humidity.

    One method to reduce water use at a CTL plant would be to use dry 
cooling. However, this will make the plants more expensive to build.
    Question 8. The auto industry has developed plug-in electric 
hybrids, and this committee has heard testimony about all-electric 
cars. Can you discuss the advantages and disadvantages of using coal to 
produce liquid fuels vs. using coal to generate electricity to charge 
batteries for electric cars and hybrids?
    Answer. If coal is to be used to replace gasoline, generating 
electricity for use in plug-in hybrid vehicles (PHEVs) can be far more 
efficient and cleaner than making liquid fuels from coal. In fact, a 
ton of coal used to generate electricity used in a PHEV will displace 
more than twice as much oil as using the same coal to make liquid 
fuels, even using optimistic assumptions about the conversion 
efficiency of liquid coal plants. This is assuming production of 84 
gallons of liquid fuel per ton of coal, and vehicle efficiency is 
assumed to be 37.1 miles/gallon on liquid fuel and 3.14 miles/kWh on 
electricity.
    The difference in CO2 emissions is even more dramatic. 
Liquid coal produced with CCS and used in a hybrid vehicle would still 
result in lifecycle greenhouse gas emissions of approximately 330 
grams/mile, or ten times as much as the 33 grams/mile that could be 
achieve by a PHEV operating on electricity generated in a coal-fired 
power plant equipped with CCS. This assumes lifecycle greenhouse gas 
emission from liquid coal of 27.3 lbs/gallon and lifecycle greenhouse 
gas emissions from an IGCC power plant with CCS of 106 grams/kWh, based 
on R. Williams et al., paper presented to GHGT-8 Conference, June 2006.
    For more detailed information on plu-in hybrid vehicles emissions 
see the NRDC factsheet ``The Next Generation of Hybrid Cars: Plug-in 
Hybrids Can Help Reduce Global Warming and Slash Oil'', at http://
www.nrdc.org/energy/plugin.pdf. This factsheet is based upon the just 
released EPRI-NRDC Joint technical Report, Environmental Assessment of 
Plug-in Hybrid Electric Vehicles, Volume 1: Nationwide Greenhouse Gas 
Emissions (1015325), July 2007 (http://www.epri-reports.org/ and http:/
/www.epri-reports.org/Volume1R2.pdf).
      Responses of Antonia Herzog to Questions From Senator Thomas
    Question 9. If coal-derived fuels are produced so they have a 
greenhouse gas profile better than the fuels they displace, would the 
NRDC support them?
    Answer. The impacts that a large coal gasification program could 
have on global warming pollution, conventional air pollution and 
environmental damage resulting from the mining, processing and 
transportation of the coal are substantial. Before deciding whether to 
invest scores, perhaps hundreds of billions of dollars in deploying 
this technology, we must have a program to manage our global warming 
pollution and other coal related impacts. Otherwise we will not be 
developing and deploying an optimal energy system.
    One of the primary motivators for the push to use coal gasification 
is to produce liquid fuels to reduce our oil dependence. The U.S. can 
have a robust and effective program to reduce oil dependence without 
rushing into an embrace of liquid coal technologies. A combination of 
more efficient cars, trucks and planes, biofuels, and ``smart growth'' 
transportation options outlined in the report ``Securing America,'' 
produced by NRDC and the Institute for the Analysis of Global Security, 
shows how to cut oil dependence by more than 3 million barrels a day in 
10 years, and achieve cuts of more than 11 million barrels a day by 
2025.
    To reduce our dependence on oil we should follow a simple rule: 
start with the measures that will produce the quickest, cleanest and 
least expensive reductions; measures that will put us on track to 
achieve the reductions in global warming emissions we need to protect 
the climate. If we are thoughtful about the actions we take, our 
country can pursue an energy path that enhances our security, our 
economy, and our environment.
    With current coal and oil consumption trends, we are headed for a 
doubling of CO2 concentrations by mid-century if we don't 
redirect energy investments away from carbon based fuels and toward new 
climate friendly energy technologies. We have to accelerate the 
progress underway and adopt policies in the next few years to turn the 
corner on our global warming emissions, if we are to avoid locking 
ourselves and future generations into a dangerously disrupted climate. 
Scientists are very concerned that we are very near this threshold now. 
Most say we must keep atmosphere concentrations of CO2 below 
450 parts per million, which would keep total warming below 2 degrees 
Celsius (3.6 degrees Fahrenheit). Beyond this point we risk severe 
impacts, including the irreversible collapse of the Greenland Ice Sheet 
and dramatic sea level rise. With CO2 concentrations now 
rising at a rate of 1.5 to 2 parts per million per year, we will pass 
the 450ppm threshold within two or three decades unless we change 
course soon.
    In the United States, a national program to limit carbon dioxide 
emissions must be enacted soon to create the market incentives 
necessary to shift investment into the least-polluting energy 
technologies on the scale and timetable that is needed. There is 
growing agreement between business and policy experts that quantifiable 
and enforceable limits on global warming emissions are needed and 
inevitable. To ensure the most cost-effective reductions are made, 
these limits can then be allocated to major pollution sources and 
traded between companies, as is currently the practice with sulfur 
emissions that cause acid rain. Further complimentary and targeted 
energy efficiency and renewable energy policies are critical to 
achieving CO2 limits at the lowest possible cost, but they 
are no substitute for explicit caps on emissions.
    A coal integrated gasification combined cycle (IGCC) power plant 
with carbon capture and disposal can also be part of a sustainable path 
that reduces both natural gas demand and global warming emissions in 
the electricity sector. Methods to capture CO2 from coal 
gasification plants are commercially demonstrated, as is the injection 
of CO2 into geologic formations for disposal. On the other 
hand, coal gasification to produce a significant amount of liquids for 
transportation fuel would not be cost-effective or compatible with the 
need to develop a low-CO2 emitting transportation sector.
    Question 10. Please explain the difference between the NRDC 
lifecycle emissions analysis and that done by the Idaho National 
Laboratory, in cooperation with Baard Energy. Please account not only 
for carbon dioxide emissions, but criteria pollutants as well.
    Does the use of a F-T coal-derived diesel product have an improved 
footprint for nitrous oxide, particulate matter, sulfur dioxide, 
volatile organic compounds, and mercury over traditional sources of 
diesel? Please quantify the per gallon differences for criteria 
pollutant emissions that would result from consumption of a F-T coal-
derived diesel product versus traditional, petroleum-derived, diesel 
fuel.
    Answer. The comparison is between the fuels analysis done by 
Argonne National laboratory, home of the GREET model, and the Baard 
Energy analysis, which used the same model.
    In a new study by the Department of Energy's Center for 
Transportation Research and Argonne National Laboratory, researchers 
Wang et. al.* found that every gallon equivalent of liquid coal 
produces nearly three times more global warming emissions than gasoline 
or diesel made from crude oil. The graph below** shows the comparison 
between liquid coal produced with low and high efficiency (42%-52% 
efficiency) without CCS produces 120-150% more global warming emissions 
than gasoline.
---------------------------------------------------------------------------
    * Wang et. al. 2007 Life-Cycle Energy and Greenhouse Gas Results of 
Fischer-Tropsch Diesel Produced from Natural Gas, Coal, and Biomass, 
Michael Wang, May Wu, and Hong Huo, Center for Transportation Research, 
Argonne National Laboratory.
    ** All graphics have been retained in committee files.
---------------------------------------------------------------------------
    Even with 85% capture of CO2, CTL emissions are still 
15-20% higher than conventional gasoline/diesel. In addition, the Wang 
study found that the liquid coal process is hugely energy consumptive 
and requires more energy input per mile than conventional crude oil 
which is shown in the graph below.
    The Baard Energy assumptions were much more aggressive in their 
analysis of a F-T plant design. It was tailored to reduce greenhouse 
gas emissions by implementing biomass as a feedstock and by selecting 
various process configurations and unit operations that allow the 
CO2 to be minimized, concentrated, and captured at optimal 
locations in the process.
    A CTL plant that operates in a conventional fashion, and which is 
not optimized, may increase greenhouse gas emissions (especially 
carbon) by 2 to 2.5 times. Only about 30% of the incoming carbon is 
converted to F-T fuels, which is eventually burned. The remaining 70% 
is emitted or vented as CO2 following shift conversion or 
combustion of the syngas (and F-T tail gas) in a gas turbine. The Baard 
Energy analysis reduced the carbon footprint by about 30% by designing 
a plant that:

          1. Utilized as much heat integration as is possible to reduce 
        the parasitic power and to help conserve water use.
          2. Used a gasifier that can operate with biomass.
          3. Optimized technology choices and methods for separating 
        the CO2.

    Question 11. You testified about a low CO2 emitting 
transportation system.
    Would the fuels used in that system meet specifications for 
military or commercial jet aviation fuel?
    Answer. There are bio-based alternative fuels which could meet the 
specification for military and commercial jet fuels that are being 
actively researched. Virgin Airlines announced back in April that it is 
working with Boeing and GE to get a jet powered by biofuels into the 
air next year. If all goes well, they could be flying commercially 
inside five years, see London Times article below.

            Virgin plans to fly 747 on biofuel in 2008
        The first commercial aircraft to be powered by biofuel will fly 
        next year in what could be a significant step towards airlines 
        reducing their oil consumption and carbon dioxide emissions.
        Virgin Atlantic is to announce today that one of its 747 jumbo 
        jets will be used to demonstrate that biofuels can power an 
        aircraft. The project, which includes Boeing and General 
        Electric, the engine-maker, hopes to have the ``green'' jumbo 
        airborne in 2008.
        The airline and its partners are testing up to eight biofuels 
        to determine which is most effective at altitude. Ethanol, 
        which is becoming an increasingly popular alternative to petrol 
        in cars, has been rejected because it does not burn well in 
        thin-oxygen environments.
        The idea of replacing petrol with biofuel in cars is a 
        significant trend in the car industry. Last year Ford announced 
        a 1 billion research project to convert more of its 
        vehicles to these new fuel sources.
        However, converting an aircraft to run on biofuel was thought 
        to be a much longer-term project and the announcement from 
        Virgin today will surprise those in the industry who have 
        scorned the idea.
        Virgin hopes that biofuel-powered aircraft could be operating 
        commercially within five years, which could help to cut 
        significantly the airline industry's carbon dioxide emissions. 
        At present air travel contributes 2 per cent to 3 per cent of 
        climate-change gases, but that level is increasing as the 
        activity expands. The industry is investing in lighter aircraft 
        and new engines to improve fuel efficiency, but biofuels could 
        eliminate oil dependence entirely.
        Sir Richard Branson, the chairman of Virgin Atlantic, launched 
        an alternative fuels division last year, pledging the profits 
        from his airline and trains for the next ten years.
        A source close to the biofuel project said: ``Everyone was 
        saying that flying a plane with alternative energy sources was 
        a decade away, but it is going much faster than that. The 
        demonstration by a 747 next year will be a milestone in the 
        airline industry's attempts to reduce its CO2 
        emissions and cut its fuel bills.''

    Question 12. Would your low CO2 emitting transportation 
system provide a single fuel that could reduce the different types in a 
military theater from nine to one or two?
    Answer. I, unfortunately, do not understand this question. The 
transportation system we envision could produce fuels with 
CO2 lifecycle emissions that can be as much as 10 times 
lower than the conventional fuels they replace. See the EPA alternative 
fuels factsheet, http://www.epa.gov/otaq/renewablefuels/420f07035.htm.
    Question 13. Your testimony indicates a substantial reliance in the 
use of plug-in hybrid vehicles. Do you have any estimates of how long 
it would take to build and deploy a fleet of plug-in hybrids to 
accomplish this goal?
    Answer. We just released a detailed report analyzing the impact of 
plug-in hybrid vehicles, see EPRI-NRDC Joint technical Report, 
Environmental Assessment of Plug-in Hybrid Electric Vehicles, Volume 1: 
Nationwide Greenhouse Gas Emissions (1015325), July 2007 (http://
www.epri-reports.org/ and http://www.epri-reports.org/Volume1R2.pdf). 
Also, see the attached NRDC factsheet ``The Next Generation of Hybrid 
Cars: Plug-in Hybrids Can Help Reduce Global Warming and Slash Oil''. 
Transportation accounts for two-thirds of our oil demand, and this 
sector is 97 percent reliant on oil. While there is no silver bullet, 
PHEVs can be part of an effective mix of strategies to dramatically cut 
our global warming pollution and oil usage in the transportation 
sector, including higher fuel efficiency, biofuels, and smart growth. 
Raising the fuel efficiency of conventional gasoline vehicles to 40 
miles per gallon (mpg) is still the fastest, cheapest way to reduce 
transportation sector global warming pollution and oil consumption, and 
it's possible to reach this goal in 10 years using existing and 
emerging technologies.
    Question 14. Has the NRDC produced any estimates of what it would 
cost American consumers to purchase these vehicles and the extent to 
which they are more or less expensive than existing vehicles?
    Answer. NRDC has not specifically done this analysis. A useful 
report we have written on the issue of costs is: In the Tank: How Oil 
Prices Threaten Automakers' Profits and Jobs. Since the late 1990s, 
Detroit's three big U.S. automakers--General Motors Corp., Ford Motor 
Company, and DaimlerChrysler--have relied heavily on large, truck-based 
sport utility vehicles to drive company profits. But with gasoline 
prices now at near-record highs, consumer demand for mid-and full-size 
SUVs is sinking fast. What if higher gas prices are here to stay and 
the trend away from gas-guzzling vehicles continues? This July 2005 
report, a joint effort from NRDC and the Transportation Research 
Institute's Office for the Study of Automotive Transportation (OSAT) at 
the University of Michigan, says that sales, profits, and American jobs 
are at risk if Detroit automakers continue with their current business 
strategy in the face of higher oil prices. The report recommends 
actions that automakers, government, and investors can take to mitigate 
the risks. http://www.nrdc.org/air/transportation/inthetank/
contents.asp.
    Question 15. Will we be able to manufacture plug-in hybrid 
airplanes, locomotives, trucks or heavy-equipment?
    Answer. Airplanes are unlikely. Locomotives already run on 
electricity. Trucks and heavy equipment could us hybrid technology, 
buses already do.
    Question 16. How do you plug in a plug-in-hybrid if you live in 
Manhattan and park on the street, or in an apartment in Seattle, or in 
a college dorm in Boise? Have you calculated the costs to these cities, 
institutions, and private property owners to provide an electrical 
socket at every parking space?
    Answer. PHEV do not need to be plugged in at every possible 
location just as a car today does not need to have the capability of 
being fueled wherever it is parked. For a further discussion of PHEV 
requirement see, EPRI-NRDC Joint technical Report, Environmental 
Assessment of Plug-in Hybrid Electric Vehicles, Volume 1: Nationwide 
Greenhouse Gas Emissions (1015325), July 2007 (http://www.epri-
reports.org/ and http://www.epri-reports.org/Volume1R2.pdf).
    Question 17. Does the NRDC factor in the origins of the feed-stocks 
used to make a particular fuel in whether or not the NRDC supports 
them? In other words, do you value domestic fuels over imported fuels, 
if all environmental aspects are equal?
    Answer. NRDC factors in the origins of the feed-stocks used to make 
a particular fuel in determining whether a fuel meets the necessary 
standards to protect the environment and public health. With today's 
persistently high oil prices, Americans are spending more money than 
ever on gasoline. The production and use of gas and diesel in cars, 
trucks, and buses also account for 27 percent of U.S. global warming 
pollution. Promising new transportation technologies such as plug-in 
hybrid electric vehicles (PHEVs) and home grown biofuels could help 
Americans spend less money at the pump, and at the same time reduce 
global warming pollution and decrease our reliance on oil.
    Question 18. China is aggressively pursuing development of a CTL 
industry. If the U.S. does not, we may be importing CTL fuels from 
China in the future. What impacts do you believe this would have on the 
national security of the United States?
    Answer. We believe it is highly unlikely that the U.S. will import 
CTL fuels from China, especially in a carbon constrained world. 
Therefore, U.S. national security will not be impacted.
    Question 19. Does the NRDC acknowledge the recent MIT study The 
Future of Coal and the premise set forth therein that coal will be an 
important energy resource in the near future for the U.S. and that this 
same premise is shared by the vast majority of scientists and research 
organizations in the U.S.?
    Answer. Please see NRDC's response to the MIT, ``The Future of 
Coal'' report, ``No Time Like the Present: NRDC's Response to MIT's 
`Future of Coal' Report'' at: http://www.nrdc.org/globalWarming/coal/
mit.pdf.
    Question 20. Has the NRDC projected energy demands and market 
response, such as the development, manufacture of vehicles, and changes 
of national infrastructure, necessary to implement their ``smart 
growth'' transportation options?
    Question 21. Have these options been validated and embraced by the 
nation's transportation industry?
    Question 22. Has the NRDC considered all of the socio-economic 
impacts of this ``smart growth'' proposal?
    Question 23. Does the NRDC recommend that U.S. markets not import 
foreign vehicles and foreign synthetic fuels which may be more 
economical than the ``smart growth'' fleet approach?
    Question 24. Does the NRDC recommend that the U.S. government 
impose tariffs or import restrictions on other countries that are 
headed towards mass production of synthetic fuels?
    Question 25. Does the NRDC believe that U.S. engineering and 
ingenuity can achieve further improvements of coal-to-liquids 
conversion technologies that will reduce greenhouse gases?
    Question 26. In your written testimony you say ``with technology 
today and on the horizon it is difficult to see how a large coal-to-
liquids program can be compatible with the low CO2-emitting 
transportation system we need to design to prevent global warming.''
    Question 27. Does this low-CO2-emitting transportation 
system exist today, anywhere in the world?
    Question 28. When will it be ready to deploy here in the United 
States?
    Question 29. Please describe this system that the NRDC believes we 
need to design.
    Answers 20-29. Please see the following NRDC reports for answers to 
these above questions.
    Driving It Home: Choosing the Right Path for Fueling North 
America's Transportation Future. North America faces an energy 
crossroads. With the world fast approaching the end of cheap, plentiful 
conventional oil, we must choose between developing ever-dirtier 
sources of fossil fuels--at great cost to our health and environment--
or setting a course for a more sustainable energy future of clean, 
renewable fuels. This June 2007 report explores the full scale of the 
damage done by attempts to extract oil from liquid coal, oil shale, and 
tar sands; examines the risks for investors of gambling on these dirty 
fuel sources; and lays out solutions for guiding us toward a cleaner 
fuel future. http://www.nrdc.org/energy/drivingithome/contents.asp.
    Biofuels: The Growing Solution to Energy Dependence and Global 
Warming. To grapple in a meaningful way with global warming and our 
dependency on oil, America will need all of the ingenuity it took to be 
the first to send a man to the moon. We need more efficient vehicles. 
And we need a clean and renewable alternative to oil. Biofuels--
especially ethanol made from biomass such as switchgrass--can make a 
tremendous contribution to ending our dependence on oil, and if 
produced and used responsibly can also be a key component of a strategy 
to beat back global warming. This index collects NRDC studies, analyses 
and other policy materials that answer many of the most pressing 
questions about these fuels. http://www.nrdc.org/air/transportation/
biofuels/contents.asp.
    In the Tank: How Oil Prices Threaten Automakers' Profits and Jobs. 
Since the late 1990s, Detroit's three big U.S. automakers--General 
Motors Corp., Ford Motor Company, and DaimlerChrysler--have relied 
heavily on large, truck-based sport utility vehicles to drive company 
profits. But with gasoline prices now at near-record highs, consumer 
demand for mid-and full-size SUVs is sinking fast. What if higher gas 
prices are here to stay and the trend away from gas-guzzling vehicles 
continues? This July 2005 report, a joint effort from NRDC and the 
Transportation Research Institute's Office for the Study of Automotive 
Transportation (OSAT) at the University of Michigan, says that sales, 
profits, and American jobs are at risk if Detroit automakers continue 
with their current business strategy in the face of higher oil prices. 
The report recommends actions that automakers, government, and 
investors can take to mitigate the risks. http://www.nrdc.org/air/
transportation/inthetank/contents.asp.

                                 ______
                                 
   Responses of Jay Ratafia-Brown to Questions From Senator Bingaman
    Question 1. You indicate that although the various technologies to 
include biomass in gasification and sequester the carbon have been 
demonstrated there is still further development necessary. How can we 
best insure that federal incentives push further development of co-
gasification with biomass and not just gasification of coal?
    Answer. I would like to first point out that Biomass R&D Technical 
Advisory Committee, created by the Biomass Research and Development Act 
of 2000 (Act), has established a national vision for bioenergy and bio-
based products. Included in its vision was the setting of a very 
challenging goal that biomass will supply 5 percent of the nation's 
power, 20 percent of its transportation fuels, and 25 percent of its 
chemicals by 2030. This goal is equivalent to 30 percent of current 
petroleum consumption and will require more than approximately one 
billion dry tons of biomass feedstock annually--a fivefold increase 
over the current consumption. This very challenging goal establishes 
the overall NATIONAL driver to develop industry incentives. Section 307 
of the Act mandated that the Secretary of Agriculture and the Secretary 
of Energy establish and carry out the so-called Biomass Research and 
Development Initiative (BRDI) under which ``competitively awarded 
grants, contracts, and financial assistance are provided to, or entered 
into with, eligible entities to carry research on, and development and 
demonstration of, biobased fuels and biobased products, and the 
methods, practices and technologies, biotechnology, for their 
production.'' Section 307(d)(2) specifically identifies gasification 
and pyrolysis as thermochemical technologies that may offer the 
capabilities ``for converting cellulosic biomass into intermediates 
that can be subsequently converted into biobased fuels and biobased 
products''--thus bringing these technologies within the purview of the 
Act and providing the mechanism by which to provide R&D incentives for 
technology development.
    To the best of my knowledge, little (if any) effort within the BRDI 
focuses on co-gasification of biomass with coal and no funding has been 
provided--presumably because of a biomass-only directive. Therefore, 
Federal R&D orientation for co-gasification within the BRDI should be 
modified or realigned to co-fund combined coal-biomass related 
projects. I also believe that specific financial incentives could be 
offered to large-scale producers of biomass waste products (e.g., 
farmers and municipalities) and large land-holders to grow/harvest/
process crop-based biomass feedstock to encourage utilization of this 
resource. Note that I have not investigated the type and application of 
such incentives.
    Question 2. You point to the need for significant R&D and 
demonstration of co-gasification and sequestration for liquid fuel 
production. Do you believe these technologies are not yet ready for 
full-scale commercialization? If not, how far off do you think they 
are?
    Answer. As I broadly discussed in my testimony, successful 
technical and cost-effective implementation of the coal-biomass-to-
liquids (CBTL) system (including sequestration) particularly depends on 
adoption of suitable gasification technology, addressing biomass 
handling challenges, satisfying syngas ``cleanup'' constraints for the 
Fischer-Tropsch process, and effectively integrating carbon capture and 
storage (CCS) technology. Each area constitutes different levels of 
technical status that impacts the commercial-readiness of the overall 
system.
    Commercial-scale co-gasification of biomass with coal has been 
successfully demonstrated at the 253 MWe Nuon IGCC power plant in 
Buggenum, The Netherlands (using the dry-feed, oxygen-blown Shell 
entrained-flow technology), as well as at Tampa Electric's 250 MWe Polk 
IGCC power plant (using slurry-feed, oxygen-blown GE entrained-flow 
technology). The latter was built in the 1990s as part DOE's Clean Coal 
Demonstration Program. Both of these plants operated normally at the 
relative levels of biomass injected (30% by weight for the Nuon plant 
and 1.5% by weight for the Polk plant). Therefore, I believe that 
existing entrained-flow gasification technology developed over the past 
25 years, with consistent DOE support, is effectively ready for large-
scale commercialization using combined coal and biomass feedstock. That 
said, R&D associated with advanced oxygen production technology, 
advanced gasifier materials, and dry-feed injection systems, currently 
being conducted by DOE, can significantly enhance operability, 
reliability, and economics of synthesis gas production as feed to the 
Fischer-Tropsch technology. Also, advanced gasification designs, such 
as the high-temperature/high-pressure `Transport Gasifier' being 
developed at DOE's Wilsonville Power System Development Facility, show 
the potential to greatly reduce the size and capital cost of future 
gasification units.
    Experience with commercial IGCC power plants, such as the Polk IGCC 
plant and the Wabash River plant (another DOE Clean Coal Technology 
Program investment), as well as refinery gasifiers, have established 
that the CBTL syngas contaminant limits can be met with appropriate 
system contaminant control methods. Thus, syngas treatment is also an 
area that is currently ready for CBTL commercialization, but can be 
further optimized with added R&D.
    While commercial-scale testing of biomass-coal co-gasification has 
shown that biomass can be successfully handled and injected into a 
high-pressure entrained-flow gasifier, cost-effective transport, 
storage and handling of crop-based types of biomass material is not 
ready for large-scale commercial co-gasification application. Biomass 
either has to be located very close to a conversion facility and 
processed immediately, or some form of ``densification'' needs to be 
implemented to mitigate handling issues. Since this is a well-
recognized issue for biomass, especially for conversion processes that 
can consume very large quantities, a number of densification methods 
have been developed that are applicable, but are currently limited to 
smaller-scale applications. Technologies, such as pelletization, 
torrefaction, and pyrolysis, and suitable logistics strategies need 
more R&D, scale-up testing, and integrated demonstration to permit the 
effective use of dispersed biomass materials. Therefore, roughly 3 to 5 
years of R&D effort is needed to bring about needed improvements and 
demonstration.
    Integration of CCS technology will reduce the greenhouse gas 
footprint of CBTL to a much greater extent than is possible with just 
co-gasifying renewable biomass materials. However, while conventional 
CO2 capture technology is commercially available and well-
proven for gasification-type applications, it increases capital 
expenditure and operating costs. Therefore, DOE is developing advanced 
membrane technologies to lower this economic impact. More importantly, 
the actual sequestration of CO2 is far from commercially 
available and acceptable, albeit years of experience with enhanced oil 
recovery (EOR) applications greatly supports this effort. As stated in 
my testimony, key challenges are to demonstrate the ability to store 
CO2 in underground geologic formations with long-term 
stability (permanence), to develop the ability to monitor and verify 
the fate of CO2, and to gain public and regulatory 
acceptance of this process. DOE's seven Regional Carbon Sequestration 
Partnerships are engaged in an effort to develop and validate CCS 
technology in different geologies across the Nation. This is vital to 
sequestration's future and use with the CBTL technology. DOE's 
programmatic goal is to demonstrate a portfolio of safe, cost-effective 
CCS technologies at commercial-scale by 2012, making it available for 
deployment for CBTL beyond 2012.
    In summary, I believe that we are likely 5 to 8 years away from 
potential commercial deployment of a large-scale CBTL facility that 
fully incorporates CCS capability. However, CBTL could be deployed in 
as little as three years with a design that allows for later inclusion 
of CCS and biomass feedstock on an as-available basis from both waste 
and cop-based sources.
    Responses of Jay Ratafia-Brown to Questions From Senator Sanders
    Question 3. The Intergovernmental Panel on Climate Change has 
recently issued its Fourth Assessment Report Summary for Policy Makers. 
In that Report they concluded that the evidence that global warming is 
real and caused by humans is unequivocal. The MIT study, ``The Future 
of Coal,'' suggested that Carbon Capture and Storage (CCS) may increase 
the cost of electricity from coal by 20%, but an aggressive energy 
efficiency campaign could be conducted, so that less electricity is 
used, bringing our electricity bills down by 20% or more. What do you 
see as the cost of liquid fuel (diesel) and gaseous fuel from coal and/
or coal-biomass with CCS versus conventional diesel and natural gas in 
the near term and long term?
    Answer. Recent economic data isn't available for a proposed CBTL 
facility. However, DOE's National Energy Technology Laboratory (NETL) 
is currently conducting a project to estimate realistic costs of diesel 
fuel produced via alternative coal-biomass co-gasification options. I 
recommend that the results of this effort be obtained for the record 
when available later in 2007.
    Note that a very recent (April 2007) RDS/SAIC/Parsons/Nexant 
assessment of a commercial scale coal-to-liquids facility producing 
50,000 barrels/day of Fischer-Tropsch liquids (Naphtha and diesel) was 
sponsored by DOE (http://www.netl.doe.gov/energy-analyses/pubs/
Baseline%20Technical%20and%20Economic- 
%20Assessment%20of%20a%20Commercial %20S.pdf). The facility also 
supplies 124 MWe net electricity to the grid and incorporates 
CO2 sequestration. Cost of the diesel portion of the F-T 
liquids is estimated to range from $1.47 to $2.45/gallon. This 
assessment indicates that project viability (based on return-on-
investment or ROI) depends heavily on crude oil prices used to produce 
conventional diesel fuel. A reference case, tied to a crude oil price 
of $61/bbl, provides a 19.8% ROI, while crude oil prices greater than 
$37/bbl would achieve ROIs greater than 10%, and a 15% ROI can be 
achieved at crude oil prices greater than $47/bbl. Policy actions were 
also shown to significantly impact expected ROIs--Federal loan 
guarantees were shown to have the largest ROI impact (increasing the 
ROI by more than 11 percentage points from the reference case) due 
mostly to an accompanying change in the debt-to-equity ratio assumed to 
finance the proposed project. F-T liquids subsidies was shown to 
provide a 9 percent increase in ROI based on the existing federal 
subsidy for liquid transportation fuels from coal of 50 cents/gallon 
($21/barrel), an incentive included in the 2005 Federal Transportation 
Bill (H. Res 109-203, Title XI, Section 11113(d)). Note that this 
credit is set to expire in 2009, so these credits would have to be 
extended in order for such a CTL (or CBTL) project to benefit 
accordingly.
    Question 4. I join Senator Murkowski in her concern about the need 
to retrofit our existing coal fired power plants to address the issue 
of carbon capture and storage. Some of the testimony suggested that 
adding ``oxyfuel'' to these older plants would be the best path to take 
as this burns pure oxygen, instead of outside air, producing a carbon 
dioxide-rich exhaust stream, with little or no NOX, so the 
CO2 is more concentrated and easier to capture for 
sequestration. Do you have any information on the ease/feasibility of 
retrofitting older coal plants or other coal-burning industrial 
facilities with ``oxyfuel''?
    Answer. Retrofitting existing coal-fired power plants to add carbon 
capture capability is being carefully investigated by boiler vendors 
with support from DOE. The two basic approaches are to integrate: 1) 
conventional amine-type scrubbing technology to remove CO2 
from the flue gas, and 2) oxygen-fired combustion or oxycombustion 
(with flue gas recirculation) to produce flue gas that is mostly 
CO2, which avoids the requirement for CO2 
scrubbing technology. Both approaches have been shown to be feasible 
with no major technical barriers other than the need for 5 to 8 acres 
of adjacent land and appropriate sequestration locations. However, both 
require considerable capital investments and significantly reduce the 
efficiency and output of a power plant.
    The basic deficiency of option 1 is that the air used for 
combustion contains nearly 80% nitrogen, which results in flue gas that 
only contains about 12% CO2 (volume basis)--the nitrogen 
dilutes the CO2 and makes it more difficult to capture. The 
use of conventional amine scrubbing to capture CO2 from flue 
gas and pressurize the CO2 for sequestration can nearly 
double the estimated cost of electricity from a conventional power 
plant (see ``Engineering Feasibility and Economics of CO2 
Capture on an Existing Coal Fired Power Plant, Alstom Power, Inc., DOE 
Final Report, June 2001).
    In the second option, the use of a high purity oxygen (>95%) can 
substantially reduce the amount of nitrogen in the product flue gas. 
While the use of pure oxygen would result in extremely high gas 
temperatures, which can exceed boiler metal temperature limitations, 
CO2 gas recirculation can be used to effectively moderate 
the gas temperatures. This approach is appropriate for retrofit 
applications of existing pulverized coal units, where the existing heat 
transfer surface has been sized for a certain gas flow and temperature 
specifications. The previously-sited study indicates that the use of a 
commercial cryogenic-type air separation unit with appropriate boiler 
modifications would represent the more cost-effective solution for a 
retrofit application. Calculated cost-of-electricity values range from 
12 to 19% lower than the corresponding values for option 1. Use of 
advanced air separation membrane technology, which should become 
commercial within several years, will significantly reduce capital 
investment and operating cost to further reduce retrofit impact on 
plant efficiency and operation (see http://www.netl.doe.gov/
technologies/coalpower/ gasification/gas-sep/index.html).
   Responses of Jay Ratafia-Brown to Questions From Senator Salazar:
    Question 5. It appears from the written testimony, that liquid 
fuels produced from coal combined with biomass can result in lower 
greenhouse gas emissions than conventional gasoline. What are the 
technology hurdles to overcome in mixing biomass with coal to produce 
liquid fuels? Has the combination of biomass and coal been used at any 
commercial plant? What is a realistic percentage of greenhouse gas 
emissions compared to petroleum that we can expect to achieve?
    Answer. TECHNOLOGY HURDLES.--While all types of gasification 
technology have been proven to be capable of converting various biomass 
feedstock, future biomass gasifiers (for production of liquid fuels) 
need to be very large by current biomass gasification standards. This 
scale requirement likely limits technologies to circulating fluidized 
bed technology and large-scale entrained flow designs used for coal (or 
high-throughput transport-type technology currently in development). 
Similarly, oxygen-blown, pressurized systems are probably essential, 
which gives the edge to the entrained flow technology.
    Recent commercial-scale biomass co-gasification experience at the 
Polk IGCC (Tampa Electric) and Nuon Buggenum IGCC plants (Nuon Power 
Buggenum BV, The Netherlands) has been performed successfully. A key 
outcome of this experience shows that biomass feed size, a critical 
design and operating parameter for the entrained-flow technology can be 
on the order of 1 mm due to biomass' high reactivity relative to coal. 
The importance of this lies in the capability to minimize biomass 
milling power consumption and possibly avoid other efficiency-reducing 
pre-treatment processes like torrefaction. The Nuon experience has also 
shown that a relatively high throughput of biomass is possible in an 
entrained-flow unit that is co-gasifying coal; up to 30% (by weight) 
has been successfully processed. While the slagging performance of the 
biomass ash is an issue, testing has shown that flux material can be 
added to the gasifier to re-establish acceptable slagging performance. 
The bottom-line is that the practical limit of biomass processing is 
probably associated more with biomass preparation and feed issues and 
desired syngas production level, than the capabilities of the 
entrained-flow gasification process and syngas cleanup system.
    The best choice for the co-gasification of syngas from biomass and 
coal at large-scale involves biomass milling to 1 mm size particles, 
compression a by piston or rotary feeder, and subsequent feed via screw 
into a high pressure/high temperature entrained-flow gasifier. 
Preferably, coal will also be fed dry to maximize efficiency. This 
option, as investigated in Europe, shows the lowest amount of unit 
operations and has the highest energy conversion efficiency. It has 
been calculated that the efficiency from wood with 35% moisture to 40 
bar syngas with H2/CO=2 is 81%. Note, however, that this 
approach is highly dependent on biomass feed technology that is 
untested and unproven for this challenging application. Other, less 
challenging design configurations make use of torrefaction to permit 
biomass feed directly with coal and coke or flash pyrolysis of the 
biomass to produce an oil/char-slurry that can more easily be pumped 
into the gasifier under pressure.
    Increased plant scale and increasing energy input from biomass 
translates into higher biomass consumption and costs due to longer 
biomass transport distances from larger growing areas. This sets up a 
potential mismatch between the appropriate scale of the pre-treatment 
portion of the processing system and the gasification portion. 
Therefore, the first configuration issue to be considered is the plant 
scale (e.g., 1,200 MWth) and its impact on the biomass capacity 
required and the likely dispersion of the biomass resources. Once the 
biomass resource capacity is generally determined by plant scale and 
relative biomass input need, pre-treatment options can be considered 
based on gasification plant design feed requirements, pre-treatment 
conversion economies-of-scale, and transport costs for alternative 
biomass intermediates. An effective way to deal with the scale 
``mismatch'' between pre-treatment and gasification may be achieved by 
splitting pre-treatment from gasification: biomass can be pre-treated 
in relatively small-scale plants close to the geographical origin of 
the biomass and the intermediate biomass feedstock is transported to 
the central large-scale plant where it is converted in combination with 
coal. The pre-treatment should preferably result in an easy to 
transport material with higher energy density. Conventional milling and 
pelletization is one possible option. Potentially more attractive is 
the use of dedicated pretreatment that also produces a feedstock that 
can be used directly and more easily in the large-scale syngas plant. 
This is represented by the production of oil/char slurry by fast 
pyrolysis or the production of torrefied wood pellets. Oil and slurry 
mixtures have a clear advantage over wood chips and straw in transport 
bulk density and notable in energy density. For longer distance 
collection of biomass, this difference may be a decisive economic 
factor. Storage and handling may also be important because of seasonal 
variations in production and demand; some storage will always be 
required. Apart from the bulk density and the energy consideration, it 
is important to note that raw biomass will deteriorate during storage 
due to biological degradation process. Char, however, is very stable 
and will not biologically degrade. Another important factor is 
handling, in which liquids have significant advantages over solids.
    To bridge the gap between the existing and proven technology for 
coal and the implementation of combined coal-biomass co-gasification, 
an R&D strategy is necessary that will focus on four interrelated 
areas:

          1. Biomass pretreatment & feeding;
          2. Gasification & burner design;
          3. Ash and slag behavior; and
          4. Syngas clean-up.

    Biomass Pretreatment & Feeding.--Biomass cannot be handled and fed 
similar to coals, as the biomass properties are completely different 
(i.e. biomass has a fibrous structure and high compressibility). 
Therefore, either biomass has to be pretreated to make it behave 
similar to coal or dedicated biomass handling systems have to be 
developed. The advantage of pre-treating the biomass to match coal 
properties (i.e. by torrefaction), is that it allows short-term 
implementation of biomass firing in existing plants. The efficiency can 
be improved when a dedicated feeding system for solid biomass is 
developed. The primary R&D issue directly related to gasification is 
how to feed a variety of biomass materials into the gasifier with 
minimum pretreatment and inert gas consumption--DOE has sponsored the 
development of the Stamet Posimetric Pump to feed solids directly into 
a gasifier at high pressure. Long term tests will be required to move 
the technology to full commercial acceptance. While there isn't any 
reason to believe that appropriately pre-treated biomass material can't 
be handled by this pump, data is required via testing of such material. 
The other major R&D priority in this area is to address the important 
issue of off-site versus on-site pre-treatment of biomass into 
intermediate forms that are both more economical to transport and 
store. This needs to consider the environmental impacts of different 
methods.
    Gasification & Burner Design.--The general objective of R&D on 
these topics is to determine the optimum burner design for solid 
biomass feeding with coal/coke and the optimum gasification conditions 
with respect to biomass particle size (does 1 mm biomass suffice), 
maximum efficiency, maximum heat recovery, minimum flux use, minimum 
inert gas consumption, complete conversion, production of biosyngas 
with desired quality (i.e. low CH4 and no tars).
    Ash and Slag Behavior.--In a slagging gasifier the ash and flux are 
present as a molten slag that protects the gasifier inner wall against 
high temperatures. The slag must have the right properties (e.g. flow 
behavior and viscosity) at the temperature in the gasifier. It is 
crucial to have a good understanding of the combined slag behavior as 
function of the gasification temperature, biomass and coal ash 
properties, and selected flux.
    Syngas clean-up.--Gas cooling from the gasifier outlet temperature 
(1000-1300 C) is normally done by a partial gas quench (to 800 C) 
with recycled clean gas or water injection. A gas quench is preferred 
considering the higher efficiency and amount of energy that can be 
recovered. However, it requires a large gas recycle (typically 1:1 to 
the raw gas) resulting in twice as large gas cleaning section (compared 
to a system without gas recycle). Therefore, there is a substantial 
incentive to develop an innovative hot gas cooler for cooling of the 
hot gas with energy recovery and to avoid the recycle. The syngas is 
further cooled to the level necessary for the gas cleaning. R&D 
activities could focus on the development of a fluidized bed gas cooler 
and other innovative designs.
    GREENHOUSE GAS EMISSIONS.--A key advantage of co-gasifying biomass 
with coal in large-scale gasifiers is the displacement of coal, a high 
carbon-content feedstock, with the renewable biomass feedstock that 
commensurately reduces carbon discharge (from syngas or liquid fuels 
utilization) based on the level of biomass heat input to the gasifier. 
Excluding carbon capture, the full level of carbon emissions reduction 
associated with the co-gasification of woody biomass depends on 
quantity of coal displaced as well as emissions related to harvesting/
transport, drying, and pulverization of this renewable resource. If 
waste heat is used as a drying medium, often a likely option, then 
harvesting/transport and pulverization represent the largest sources. 
Given the high efficiency of large-scale harvesting methods, 
pulverization will likely represent the largest source of exogenous 
carbon emissions for the woody biomass. Pulverization of waste wood has 
been estimated to yield 29 kg CO2/metric ton, based on data 
from Denmark. Relative to pulverization yield of CO2, the 
transport of biomass is approximately an order of magnitude lower in 
value. Therefore, harvesting/transport and pulverization of woody crops 
for fuels production will yield about 32 kg CO2/metric ton 
biomass supplied, which is less than 2% of the total carbon content of 
the wood (per CO2-equivalent) that is effectively recycled.
    Relative to fuels refined from crude petroleum, coal-to-liquids 
(CTL) production (without integrated CO2 capture) emits 2 to 
2.5 times as much CO2 per unit volume of liquid fuel. With 
integrated CO2 capture, CTL yields approximately the same 
CO2 emissions as petroleum refining. Replacement of a 
portion of the coal feedstock with biomass (CBTL) will reduce 
CO2 emissions for facilities without or with integrated 
CO2 capture capability. For the former, 50 to 60 percent of 
the coal input would need to be replaced to yield CO2 
emissions equivalent to that of petroleum refining; however, due to the 
lower energy content of biomass, about 1.4 tons of biomass would need 
to replace each ton of coal to maintain equivalent liquids production 
level (about 60% biomass and 40% coal by weight). For a CBTL facility 
with integrated CO2 capture, a carbon-neutral facility would 
require that coal consumption be reduced by about one-third via 
replacement with an energy equivalent quantity of biomass, resulting in 
a facility utilizing approximately 60% coal and 40% biomass by weight. 
Higher levels of biomass feed will result in a net reduction of 
CO2.
    Question 6. Even with the use of biomass, there are still 
substantial volumes of CO2 that must be captured and safely 
stored. Are there any recommendations this panel has on where to locate 
CTL facilities to facilitate the storage of CO2?
    Answer. I note for the record that key CO2 storage 
issues are: 1) Storage period--should be prolonged, preferably hundreds 
to thousands of years; 2) Cost of storage (including the cost of 
transportation from the source to the storage site)--must be reduced; 
3) Risk of release--must be understood and be minimized or eliminated; 
4) Environmental impact--must be minimal; and 5) Regulatory/legal 
impact--storage method should not violate national or international 
laws and regulations.
    Storage media currently considered include geologic sinks and the 
deep ocean. Geologic storage includes deep saline formations 
(subterranean and sub-seabed), depleted oil and gas reservoirs, 
enhanced oil recovery, and unminable coal seams. Deep ocean storage 
includes direct injection of liquid CO2 into the water 
column at intermediate depths (1000-3000 m), or at depths greater than 
3000 m, where liquid CO2 becomes heavier than sea water, so 
it would drop to the ocean bottom and form a so-called ``CO2 
lake.'' In addition, other storage approaches are proposed, such as 
enhanced uptake of CO2 by terrestrial and oceanic biota, and 
mineral weathering. Captured CO2 can also be utilized as a 
raw material for the chemical industry; however, the prospective 
quantity of CO2 that can be utilized is a very small 
fraction of CO2 emissions from anthropogenic sources. 
Combined storage and utilization can be practiced via enhanced oil and 
gas recovery schemes.
    Since DOE has established an extensive R&D program to fully 
investigate all options related to CO2 capture and 
sequestration, I recommend that the committee review the DOE program, 
its goals, and progress to-date. I fully concur with Mr. James Bartis 
of Rand corporation who recommended that the U.S. government take 
action as appropriate and as soon as feasible to conduct multiple 
large-scale demonstrations of geologic sequestration at various 
strategic locations across the United States.
    Question 7. Can you discuss the water requirements for a CTL plant? 
Are there opportunities for reusing/recycling water in the process?
    Answer. I have briefly investigated the issue of CTL water 
consumption versus that of a conventional petroleum refinery: 
calculations are based on recent DOE/NETL studies for `IGCC with 
sequestration' (IGCC/S) and CTL (50,000 Bbl/day facilities). Both 
studies used Conoco-Philips gasifiers. The IGCC/S study included an 
assessment of water consumption, but the CTL study did not. I have 
compared the two based on syngas production and condenser duty. While 
most of the water consumption is associated with the water-gas-shift 
steam and cooling tower make-up, a small portion of the water 
consumption can be considered associated with the net electricity 
production of the CTL plant. Based on syngas flow and condenser duty 
ratios for these plants, I estimate a water consumption range for the 
CTL plant of roughly 6 to 8 Bbl water per Bbl of F-T liquids for a 
conventional CTL plant design. [Note that a recent Mitretek [now 
Noblis] study indicates that a properly designed CTL plant can reduce 
water consumption to 1Bbl/Bbl F-T liquids via use of dry cooling 
towers: ``A Techno-Economic Analysis of a Wyoming Located Coal-to-
Liquids (CTL) Plant,'' sponsored by DOE/NETL] This compares with 
conventional refinery numbers ranging from 1.85 to 2.6 Bbl water/Bbl of 
processed crude. Conventional CTL water consumption apparently needs to 
be cut by 55 to 75% to achieve the same water consumption rate as a 
conventional refinery. The previously mentioned study shows that this 
is doable at a higher capital investment.
    Question 8. The auto industry has developed plug-in electric 
hybrids, and this committee has heard testimony about all-electric 
cars. Can you discuss the advantages and disadvantages of using coal to 
produce liquid fuels vs. using coal to generate electricity to charge 
batteries for electric cars and hybrids?
    Answer. CTL and CBTL plants can produce both liquid fuels and 
electricity for sale to the grid. These products are not mutually 
exclusive of one another, and the mix of electricity to liquids 
production can be adjusted within the framework of the plant design and 
modified even after a plant has been built. Therefore, such a facility 
has the capability to flexibly serve multiple markets and adjust to 
market demand for liquid fuels and electricity.
    Responses of Jay Ratafia-Brown to Questions From Senator Thomas
    Question 9. We are told that Fischer-Tropsch fuels require no 
modifications to existing diesel or jet engines, or delivery 
infrastructure including pipelines and fuel station pumps. Is that 
true?
    Answer. The F-T diesel (FTD) produced by CTL and CBTL is a high-
value fuel that is superior to petroleum-based diesel in a number of 
ways, principally the high cetane number, which reduces combustion 
noise and smoke, and because it is sulfur, nitrogen and aromatic-free. 
Below, I briefly discuss the qualities of FTD versus standard No. 2 
diesel fuel (D2).
                              fuel quality
    FTD is much closer to D2 by quality (lubricity, heating value, 
viscosity, ignition temperature) than most of the other fuel 
substitutes, such as methanol and ethanol, and will require no, or very 
insignificant, modifications to equipment currently fueled by 
petroleum-based diesel fuel.
    Lubricity is especially important for compression-ignition engines 
and for gas turbines, as the liquid fuel serves in these devices as a 
lubricant for pumping systems. In the case of diesel fuel, the fuel 
acts as a lubricant for the finely fitting parts in the diesel fuel 
injection system. While all diesel fuel injection systems depend on the 
fuel to act as a lubricant, rotary pump-style injection systems seem to 
be the most sensitive to fuel lubricity. Lubricity of FTD fuel is in 
the range of the lubricity of D2 and its use will not require any 
changes in the pumping system or additions of special lubricity agents.
    The flash point of liquid fuel, a measure of fuel stability, is the 
lowest temperature at which sufficient vapor is given off to form a 
momentary flash when a flame is brought near the surface. The flash 
point for FTD is almost equal to that of D2. FTD also has viscosity in 
the same range as D2.
    [Note that an additive package may also be added to the raw FTD in 
order to bring the fuel up to specification for sale as diesel fuel to 
the end-use consumer. These additives are used to improve performance, 
handling, stability and potential contamination and are commonly used 
for petroleum-based diesel as well.]
                         fuel toxicity and odor
    FTD fuel is colorless, odorless, and low in toxicity.
    Toxicity.--The U.S. DOE Status Report\1\ discusses results of a 
comparative study on emissions of the four ``Toxic Air Contaminants'' 
from diesel exhaust listed in the Clean Air Act (benzene, formaldehyde, 
acetaldehyde, and 1,3 butadiene) along with toxic polycyclic aromatic 
hydrocarbons, both in the gas phase and bound in particulate matter. 
The study showed FTD to have among the lowest emissions of the test 
fuels for almost all of the toxic compounds analyzed, and lower 
emissions than petroleum diesel for all of them. Tests on mammals given 
acute exposures to the FTD fuel itself--oral, skin and eye--also 
indicated that the FTD test fuel itself is less toxic than petroleum 
diesel.
---------------------------------------------------------------------------
    \1\ Status Review Of Doe Evaluation Of Fischer-Tropsch Diesel Fuel 
As A Candidate Alternative Fuel Under Section 301(2) Of The Energy 
Policy Act Of 1992.
---------------------------------------------------------------------------
    Biodegradation.--Laboratory test data submitted by Shell and 
Syntroleum for FTD compared to petroleum diesel, and a group of blends 
of FTD with petroleum diesel, confirm that FTD will be roughly 
comparable in biodegradation to petroleum diesel overall.
    Ecotoxicity.--Ecotoxicity data have been submitted by Syntroleum 
and by Shell. Tests were done on mysid shrimp, various freshwater fish, 
algae, and bacteria. All of these tests showed low toxicities for FTD 
by showing that only at high concentrations, if at all, were there 
significant mortalities. Overall, available data indicate that FTD 
should have considerably lower ecotoxicity than petroleum diesel.
                               emissions
    Information from the California Energy Commission,\2\ where 
unmodified diesel engines, fueled with neat FTD fuel (derived from NG), 
showed the following average emission reductions per mile compared to 
typical California diesel fuel:
---------------------------------------------------------------------------
    \2\ Gas-to-Liquid Fuels In Transportation. California Energy 
Commission Webpage.

   Hydrocarbons--30%
   Carbon Monoxide--38%
   NOX--8%
   Particulates--30%.

    Question 10. Can biomass co-feed CTL technology jump-start the 
cellulosic biomass fuels industry?
    Answer. In my mind, the terminology ``cellulosic biomass fuels 
industry'' connotes technology that aims to extract fermentable sugars 
from cellulose-based feedstock (e.g., acid hydrolysis enzymatic 
hydrolysis) to produce liquid fuels such as ethanol. Compared to this 
``sugar-based framework,'' that produces sugar feedstock for 
processing, gasification represents an alternative ``thermochemical-
based framework'' that thermally converts the hydrocarbon building 
blocks of cellulosic material into synthesis gas (CO and H2) 
for further conversion into fuels via the Fischer-Tropsch technology. 
Therefore, I don't see the CBTL technology as ``jump-starting'' the 
cellulosic biomass fuels industry from the perspective of moving the 
sugar-based technology platform forward, except from a competitive 
perspective.
    That being said, the primary philosophy behind CBTL is to jump-
start the thermochemical-based cellulosic biomass fuels industry, both 
rapidly and cost-effectively, by utilizing the technological strengths 
of large-scale, commercial coal gasification technology that has been 
developed over the past 25 years, as well as the use of coal as the 
base feedstock that assures consistent operation. This also relies on 
the environmental strengths that `advanced gasification with integrated 
carbon capture', key components of CBTL, can bring to the table.
    Question 11. In addition to financial incentives, in the form of 
tax credits, appropriations, and other tools at Congress' disposal, 
what regulatory approaches do you believe can be taken to advance the 
development of a domestic coal-derived fuel industry? Please address 
not only liability issues associated with carbon dioxide sequestration, 
but permitting of the actual plants, obstacles to construction of 
infrastructure, and other issues that you believe could be addressed 
from a regulatory, rather than a financial, standpoint.
    Answer. While financial incentives are the most critical in 
reducing business risk to early commercial projects, Siting Risk and 
Regulatory and Permitting Uncertainty have been identified in various 
large-scale gasification system assessment surveys as critical to 
project risk reduction. Significant siting and permitting risk is 
associated with the primary conversion facility, feedstock (both coal 
and biomass) delivery methods and routes, fuel and CO2 
pipelines (assuming sequestration), feedstock storage (coal and 
biomass), electricity transmission lines, byproduct storage/handing 
facilities (e.g., ash and slag, sulfur containment), and CO2 
repository (if needed for sequestration, and which may well be located 
in a different locale than the primary plant). Recommended risk 
reduction via regulation can implement:

   Generic and uniform licensing standards for siting and 
        permitting facilities in multiple jurisdictions within a 
        region;
   Coordination among Federal agencies, State environmental and 
        permitting agencies, and state utility rate-setting entities 
        (PUCs) to facilitate national, regional, and state energy and 
        environmental regulations and policies.
   Federal or state indemnification for facility byproducts 
        (e.g. slag, hydrogen, liquid fuels, sequestered 
        CO2).

    Siting Risk.--The sheer number and variety of siting issues can 
create significant delays in approving and permitting a conversion 
facility, continuing to push back market entry. Major acceptability and 
siting concerns that have been identified are the cost of electricity 
in a community, jobs, availability and proximity of local resources, 
fuel diversity, available transmission capacity, potential local and 
regional air and water impacts, byproduct/waste disposal concerns, 
transmission line and pipeline rights-of-way, the NIMBY effect, and 
general negative perceptions of large coal/biomass-consuming plants.
    Permitting Risk.--A substantial number and variety of siting issues 
for a project can create significant delays in approving and permitting 
a plant, which may be a factor in delaying entry into the market. Since 
CBTL is not an established energy conversion technology, the permitting 
process can be extensive and very complex with regard to environmental 
and construction permitting. Federal and state regulators should 
develop uniform licensing standards and regulations for CTL/CBTL plants 
(including cogeneration), as well as a single, dedicated information 
source and database that can assist in the siting and permitting of 
plants and procurement of technology and equipment for projects. The 
states should also develop Memoranda of Understanding specifying 
compatible regional standards to address air shed issues associated 
with facility permitting. Regulation could establish a multi-
jurisdictional state/federal-working group to deal with regulatory 
implementation issues, in cooperation with the National Association of 
Regulatory Utility Commissioners (``NARUC'').
    Regulatory Risk.--The regulatory uncertainty associated with future 
national environmental standards and the licensing/permitting 
requirements in different locations represents important barriers to 
technology adoption. Uncertainty regarding future regulation of plant 
emissions, especially CO2, makes it is difficult for 
stakeholders to accurately assess the economic and financial value of 
adopting CTL/CBTL technology (e.g., forward value of emissions 
reductions). In addition, the environmental regulations specifically 
applicable to gasification-type technology have, so far, been confusing 
and differ from that of coal combustion-based plants due to the unique 
design characteristics of gasification technology (e.g., use of a 
combustion turbine to generate power).
    Recent EPA multi-pollutant environmental regulations help reduce 
the uncertainty of emissions regulations related to NOX, 
SOX, and mercury. In March 2005, EPA issued both the Clean 
Air Interstate Rule (CAIR) and the Clean Air Mercury Rule (CAMR) that 
will permanently cap emissions of sulfur dioxide (SO2) and 
nitrogen oxides (NOX) in the eastern United States and DC, 
and permanently cap and reduce mercury emissions from coal-fired power 
plants. While this does not preclude the adoption of further 
legislation that will alter these new rules, they likely identify 
minimum emissions reduction standards. On this basis, added appropriate 
measures could be regulated to perhaps monetize or otherwise recognize 
the future value of emissions allowances, and a definitive set of 
accounting standards reflecting the valuation of these credits could 
also be developed.
    A highly critical factor associated with regulatory risk is the 
possibility of future carbon limits. The uncertainty surrounding such 
future regulation increases project risk substantially, which can be 
relieved via appropriate legislation/regulation to indemnify 
CO2 pipelines and storage facilities. As an example, the 
sate of Texas passed legislation that establishes ownership of 
CO2 captured by DOE's FutureGen clean coal project--the 
state will provide indemnification for the CO2 permanently 
stored in deep underground formations and also retains the right to 
sell CO2 for enhanced oil recovery if not injected. However, 
projects that exceed state boundaries may cause problems that could be 
dealt with via national legislation and regulation to foster 
appropriate regional solutions.
    Question 12. What specific technology gaps need to be closed by DOE 
and private industry working together to reduce the technical and 
economic risk of coal-derived fuel plants?
    Answer. With respect to CBTL technology gaps, please see my answer 
to question 5. Please note that I fully concur with the testimony of 
Mr. James Bartis of Rand Corporation with regard to required steps that 
should be taken to reduce risk and quickly move this technology 
forward, namely: 1) cost-share in the development of a several site-
specific commercial plants based on coal and/or a combination of coal 
and biomass; 2) foster early commercial experience by firms or groups 
with the technical, financial, and management capabilities to 
successfully carry out large-scale projects of this type and to capture 
and exploit the learning that will accompany actual plant operations; 
3) conduct multiple demonstrations and, by way of such demonstrations, 
develop the regulatory framework required for a commercial 
sequestration industry; and 4) increase support of RD&D, testing and 
evaluation of advanced concepts and subsystems for integrating coal and 
biomass for the production of liquid fuels via gasification and Fisher-
Tropsch technologies.
    Question 13. Specifically, what technology gaps or market 
limitations would prevent adding large amounts of biomass to a coal 
gasifier? At what stage is this research and development?
    Answer. The practical limit of biomass processing is probably 
associated more with biomass preparation and feed issues and desired 
syngas production level, than the capabilities of the entrained-flow 
gasification process and syngas cleanup system. As cited in my answer 
to question 5, a key technology limitation is associated with high-
throughput, dry feed of coal + biomass into a high temperature/pressure 
entrained flow gasifier. DOE has sponsored the development of the 
Stamet Posimetric Pump to feed solids directly into a gasifier at high 
pressure, which is critical breakthrough if it can reliably handle both 
coal and biomass. This pump was originally developed to permit feeding 
oil shale into gasifier systems and to provide positive flow control. 
The device consists of a single rotating element that is made up of 
multiple disks and a hub that are installed inside a stationary 
housing. Material entering the pump becomes locked between the discs 
and is carried around by their rotation, which means the pump 
experiences virtually no wear. The housing is equipped with an abutment 
that directs the coal/biomass out of the discharge and makes the pump 
self-cleaning. In total, there are over 150 of these units installed at 
commercial facilities, but all are used in atmospheric applications. In 
recent DOE sponsored tests, it was able to feed coal (lignite, 
bituminous, and PRB) to a pressure of 560 psia. The ultimate goal of 
the development program is to achieve 1000 psia. Long term tests will 
be required to move the technology to full commercial acceptance, 
particularly for biomass. While there isn't any reason to believe that 
appropriately pre-treated biomass material can't be handled by this 
pump, data is required via accelerated testing of such material. Note 
also that a piston compressor has been developed in Europe in which 
approximately 50 times less inert gas is consumed to feed solids.
    Handling and treatment of biomass feedstock for co-gasification 
represents perhaps the most significant technical issue from an 
operational perspective that would limit biomass feed. While testing 
has shown good performance with co-gasification of woody biomass and 
coal, transferring the material to the plant and into the gasifier in a 
suitable form is critical to performance and overall efficiency. A 
complete feed system tailored to the particular biomass fuel must be 
used if plant availability (with biomass) is to be maintained. 
Significant quantities of biomass will be required to produce a small 
portion of the plant's power due to the relatively low energy density 
of biomass fuel. Consequently, the supplemental biomass feed system(s) 
could be physically almost as large as the feed system for normal solid 
fuel such as coal or petroleum coke.
    Biomass Transport.--Fuel transport is a major environmental concern 
worldwide. Woody biomass and grasses are a dispersed resource that 
requires road transport. This has provoked local protest and has proved 
a significant, if not the major factor in the failure of at least one 
biomass power plant in Europe to obtain planning permission. Even in 
cases where additional road transport is under 1% of current heavy-duty 
truck traffic, this has been sufficient to provoke protest. Plant 
operators with a brand image to protect are particularly sensitive to 
such public concern. European experience has shown that feedstock 
transport to a large-scale plant is always a contentious area. Even 
plants where almost all the local biomass is to arrive via dual 
transport methods have been refused planning permission, most of the 
objections being on traffic grounds. The difficulties in fuel delivery 
should not be underestimated and, therefore, studied closely.
    Transport of biomass is expensive due to generally low bulk 
densities of biomass fuels and since the cost of biomass fuel is a 
critical factor in the economics of co-gasifying, the costs of 
transportation (and thus transport distances) are very important 
issues. In general biomass heating values [MJ/kg] and particle 
densities are about half of that of coal, whereas bulk raw densities 
[kg/m3] are about 20% of that of coal, resulting in overall 
biomass energy density [MJ/m3] approximately 10% of coal. As 
a consequence, when co-gasifying raw biomass at a 10% heat input rate 
with coal, the volume of coal and biomass can be similar and therefore 
biomass requirements with regard to transport, storage and handling are 
very high in comparison to its heat contribution.
    Biomass Pretreatment & Feeding.--Biomass cannot be handled and fed 
similar to coals, as the biomass properties are completely different 
(i.e. biomass has a fibrous structure and high compressibility). 
Therefore, either biomass has to be pretreated to make it behave like 
coal or dedicated biomass handling systems have to be developed. The 
advantage of pre-treating the biomass to match coal properties (i.e. by 
torrefaction), is that it allows short-term implementation of biomass 
firing in existing plants. The pre-treatment should preferably result 
in an easy to transport material with higher energy density. 
Conventional milling and pelletization is one possible option. 
Potentially more attractive is the use of dedicated pretreatment that 
also produces a feedstock that can be used directly and more easily in 
the large-scale syngas plant. This is represented by the production of 
oil/char slurry by fast pyrolysis or the production of torrefied wood 
pellets. Oil and slurry mixtures have a clear advantage over wood chips 
and straw in transport bulk density and notable in energy density. For 
longer distance collection of biomass, this difference may be a 
decisive economic factor. Storage and handling may also be important 
because of seasonal variations in production and demand; some storage 
will always be required. Apart from the bulk density and the energy 
consideration, it is important to note that raw biomass will 
deteriorate during storage due to biological degradation process. Char, 
however, is very stable and will not biologically degrade. Another 
important factor is handling, in which liquids have significant 
advantages over solids. This is an area that requires comprehensive R&D 
and large-scale demonstration efforts in the U.S. if energy crops are 
to be supplied in sufficient quantities to CBTL facilities around the 
country. Only small-scale efforts have been supported to-date.
    Question 14. What research and demonstration steps are necessary 
for wide-scale commercial implementation of carbon capture and 
sequestration?
    Answer. CO2 Capture.--I would like to point out that DOE 
has been conducting a relatively extensive R&D program related to 
CO2 capture and sequestration for combustion-based power 
systems (e.g., pulverized coal-fired plants that exhaust combustion 
flue gas at atmospheric pressure) and gasification-based energy 
conversion systems (e.g., Integrated Gasification Combined Cycle power 
plants that operate at high pressure). Fortunately for the CBTL 
technology, which is gasification-based, CO2 capture is 
significantly more cost-effective than for combustion-based capture 
systems, even with existing state-of-the-art physical absorption 
technology. This is primarily due to high pressure operation with high-
purity oxygen, as well as the capability to increase the CO2 
concentration of the synthesis gas to about 40%. Advanced membranes and 
other novel separation methods are being developed to minimize the cost 
and efficiency losses for both hydrogen and CO2 separation. 
These technologies are appropriate for both IGCC and CBTL applications. 
The key is to move these capture technologies to the pilot-scale as 
soon as possible at existing U.S. IGCC plants, Dakota Gasification 
Plant, or pilot gasification facilities like DOE's Wilsonville Power 
Systems Development Facility (PSDF).
    CO2 Transport and Injection.--Since industry already has 
a great deal of experience with long-distance CO2 pipelines 
and CO2 injection components, no R&D is required. For 
example, Denver City, Texas, is the world's largest CO2 hub, 
distributing gas from the 502 mile-long Cortez Pipeline (running from 
Colorado to Texas), having a capacity of 1 to 4 billion cubic feet per 
day. A cadre of delivery lines carries the gas from Denver City to the 
40+ oil fields presently under CO2 flood in Texas' Permian 
Basin. The Dakota Gasification Company, located in Beulah, North 
Dakota, produces more than 54 billion standard cubic feet of natural 
gas annually from lignite coal gasification that exceeds 6 million tons 
each year; they capture CO2 from the syngas and send it 
through a 205 mile pipeline to EnCana's Weyburn oil field in Canada.
    CO2 Sequestration.--Sequestration of CO2 in 
geologic formations cannot achieve a significant role in reducing GHG 
emissions unless it is fully acceptable to the various stakeholders, 
regulators, and above all the general public. For geologic 
sequestration to be a viable technology to mitigate climate change, the 
risks associated with this activity must be extensively evaluated in 
R&D efforts, including ecological, environmental, operational, health 
and safety, and economic risks. The major risks associated with the 
operation of an underground CO2 storage project are largely 
related to leakage from the storage structure and the transport system. 
While CO2 is not classified as a toxic material, by 
displacing oxygen in high enough concentrations it can cause 
asphyxiation and rapid death. Furthermore, in addition to being a 
potential health hazard, any leakage of CO2 back into the 
atmosphere completely negates the effort expended in sequestering the 
CO2. Two types of CO2 releases are possible, slow 
leakage through slightly permeable cap rock, and catastrophic releases 
due to rupture of a pipeline, failure of a field well, or opening of a 
fault. There is also the potential for sequestered CO2 to 
leak into non-saline aquifers, which could cause problems with potable 
uses of this water. As discussed previously, years of operation with 
natural gas pipelines (and CO2 pipelines for enhanced oil 
recovery [EOR]) should provide the experience needed for the safe 
design and operation of CO2 pipelines. However, there is 
always the chance that seismic or building activity could lead to 
pipeline rupture. A risk analysis conducted for the Weyburn EOR project 
indicated that the most probable path for transmission of 
CO2 from one stratum to another or to the biosphere is along 
a well bore. Therefore, wells must be carefully drilled and monitored. 
If CO2 sequestration is practiced in depleted oil and gas 
fields, then the presence of abandoned wells could cause problems. 
These wells will need to be effectively plugged and monitored. 
Potential health risks from slow leakage are considerably greater if 
H2S, SOX or NOX are sequestered along 
with CO2. R&D needs to fully investigate and identify those 
aspects of geologic sequestration that present probable risks (which 
are different for each type of formation), appropriate actions can be 
taken prior to the commencement of injection activities to obviate 
occurrence of problems.
    I strongly recommend the use of Probabilistic Risk Assessment (PRA) 
as the preferred methodology for overall evaluation the complex, long 
timeframe, process-driven geological storage of CO2. It 
takes hundreds of parameters to describe the reservoir, the surrounding 
geosphere, the CO2, water and other physical properties and 
the injection wells. These parameters and processes interact to make up 
a complex series of possible outcomes and impacts. PRA can 
statistically quantify the uncertainty associated with the parameters, 
describing the processes in deterministic model(s) and can integrate 
all possible outcomes (all combinations of parameter perturbations), 
including interactions. PRA can be used to focus government/private 
resources on the most important parameters and processes and can 
effectively guide both the science and regulation. It provides a 
statistically rigorous method of ranking geological and anthropogenic 
parameters and processes within a systems-oriented CO2 
storage model. The PRA methodology can also be used to address health 
and safety concerns, and economic performance factors.
    I commend DOE's efforts to form a nationwide network of regional 
partnerships to help determine the best approaches for capturing and 
permanently storing CO2. Seven government/industry Regional 
Carbon Sequestration Partnerships are currently determining the most 
suitable technologies, regulations, and infrastructure needs for carbon 
capture, storage, and sequestration in different areas of the country. 
Based on the outcomes of these partnerships, I strongly recommend that 
the government rapidly conceive and take appropriate steps to conduct 
multiple large-scale demonstrations of geologic sequestration at 
various sites across the United States. All steps necessary must be 
taken to guarantee adequate monitoring, mitigation, and verification 
(MM&V) aimed at providing an accurate accounting of stored 
CO2 and a high level of confidence that the CO2 
will remain sequestered permanently. Appropriate representation from 
watchdog environmental groups need to be included in the oversight of 
these projects to assure objectivity and to gain widespread public 
acceptance.
    Question 15. Does the use of a FT coal-derived diesel product have 
an improved footprint for nitrous oxide, particulate matter, sulfur 
dioxide, volatile organic compounds, and mercury over traditional 
sources of diesel? Please quantify the per gallon differences for 
criteria pollutant emissions that would result from consumption of a FT 
coal-derived diesel product versus traditional, petroleum-derived, 
diesel fuel.
    Answer. Please see my answer to Question 9.
    Question 16. China is aggressively pursuing development of a CTL 
industry. If the U.S. does not, is it possible that we will be 
importing CTL fuels from China in the future?
    What implications does this have for U.S. national security?
    Answer. I am of the strong opinion that our own actions relative to 
CTL and CBTL deployment are what count most with regard to our energy 
security and national security. Secondarily, and accounting for 
comparable environmental considerations, we should strongly encourage 
and work with the Chinese to help them develop their own indigenous 
fuel resources. This will relieve pressure on petroleum consumption 
around the world and be highly positive for consumers in all countries, 
while reducing purchases of crude oil from areas of the world that do 
pose real energy and security threats to the U.S. Considering China's 
significant growth and voracious appetite for fuels, it seems highly 
unlikely that they will be selling their domestically-produced fuel 
products, except perhaps to much closer neighboring countries. If our 
country takes appropriate and timely steps to utilize our own natural 
resources wisely, then we can become more secure and confident about a 
promising future with adequate energy supply. Let's not leave it to the 
next generation to satisfy these critical responsibilities.

                                    

      
