[Senate Hearing 110-265]
[From the U.S. Government Publishing Office]


                                                        S. Hrg. 110-265
 
 CLEAN COAL, OIL AND GAS DEVELOPMENT, NEW ENERGY OPPORTUNITIES THROUGH 
                       CARBON CAPTURE AND STORAGE 

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

                                HEARING

                                before a

                          SUBCOMMITTEE OF THE

            COMMITTEE ON APPROPRIATIONS UNITED STATES SENATE

                       ONE HUNDRED TENTH CONGRESS

                             FIRST SESSION

                               __________

                            SPECIAL HEARING

                     AUGUST 13, 2007--BISMARCK, ND

                               __________

         Printed for the use of the Committee on Appropriations


  Available via the World Wide Web: http://www.gpoaccess.gov/congress/
                               index.html

                               __________

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                      COMMITTEE ON APPROPRIATIONS

                ROBERT C. BYRD, West Virginia, Chairman
DANIEL K. INOUYE, Hawaii             THAD COCHRAN, Mississippi
PATRICK J. LEAHY, Vermont            TED STEVENS, Alaska
TOM HARKIN, Iowa                     ARLEN SPECTER, Pennsylvania
BARBARA A. MIKULSKI, Maryland        PETE V. DOMENICI, New Mexico
HERB KOHL, Wisconsin                 CHRISTOPHER S. BOND, Missouri
PATTY MURRAY, Washington             MITCH McCONNELL, Kentucky
BYRON L. DORGAN, North Dakota        RICHARD C. SHELBY, Alabama
DIANNE FEINSTEIN, California         JUDD GREGG, New Hampshire
RICHARD J. DURBIN, Illinois          ROBERT F. BENNETT, Utah
TIM JOHNSON, South Dakota            LARRY CRAIG, Idaho
MARY L. LANDRIEU, Louisiana          KAY BAILEY HUTCHISON, Texas
JACK REED, Rhode Island              SAM BROWNBACK, Kansas
FRANK R. LAUTENBERG, New Jersey      WAYNE ALLARD, Colorado
BEN NELSON, Nebraska                 LEMAR ALEXANDER, Tennessee

                    Charles Kieffer, Staff Director
                  Bruce Evans, Minority Staff Director
                                 ------                                

              Subcommittee on Energy and Water Development

                BYRON L. DORGAN, North Dakota, Chairman
ROBERT C. BYRD, West Virginia        PETE V. DOMENICI, New Mexico
PATTY MURRAY, Washington             THAD COCHRAN, Mississippi
DIANNE FEINSTEIN, California         MITCH McCONNELL, Kentucky
TIM JOHNSON, South Dakota            ROBERT F. BENNETT, Utah
MARY L. LANDRIEU, Louisiana          LARRY CRAIG, Idaho
DANIEL K. INOUYE, Hawaii             CHRISTOPHER S. BOND, Missouri
JACK REED, Rhode Island              KAY BAILEY HUTCHISON, Texas
FRANK R. LAUTENBERG, New Jersey      WAYNE ALLARD, Colorado

                           Professional Staff

                               Doug Clapp
                             Roger Cockrell
                         Franz Wuerfmannsdobler
                        Scott O'Malia (Minority)
                         Brad Fuller (Minority)

                         Administrative Support

                              Robert Rich





















                            C O N T E N T S

                              ----------                              
                                                                   Page
Opening Statement of Senator Byron L. Dorgan.....................     1
Statement of Carl O. Bauer, Director, National Energy Technology 
  Laboratory, Department of Energy...............................     4
    Prepared Statement...........................................     5
How is DOE Responding to These Issues?...........................     6
Opportunities for Synergy Between Coal and Oil Industries........     7
Statement of Ronald R. Harper, Chief Executive Officer and 
  General Manager, Basin Electric Power Cooperative..............    16
    Prepared Statement...........................................    17
A Comprehensive Solution to a Complex Problem....................    18
Coal--a Necessary Part of the Solution...........................    18
An Example for the Future--the Great Plains Synfuels Plant.......    18
Two Paths Forward for Coal.......................................    19
Technology Horserace--a Balanced Approach to Incentives..........    19
Enhanced Oil Recovery--a Bridge for Technology...................    20
Statement of John Weeda, Plant Manager, Coal Creek Station, Great 
  River Energy...................................................    20
    Prepared Statement...........................................    22
Statement of Rod Nelson, Vice President, Schlumberger Limited on 
  Behalf of the National Petroleum Council.......................    23
    Prepared Statement...........................................    25
NPC Report Findings and Background...............................    25
Carbon Capture and Sequestration.................................    27
Statement of Jeffrey N. Phillips, Program Manager, Electric Power 
  Research Institute.............................................    30
    Prepared Statement...........................................    32
Summary of Key Points............................................    33
Accelerating RD&D on Advanced Coal Technologies with 
  CO2 Capture and Storage--Investment and Time 
  Requirements...................................................    33
Reducing CO2 Emissions Through Improved Coal Power 
  Plant Efficiency...............................................    35
New Plant Efficiency Improvements--IGCC..........................    36
New Plant Efficiency Improvements--Advanced Pulverized Coal......    40
Improving CO2 Capture Technologies....................    44
Pre-combustion CO2 Capture (IGCC).....................    44
Post-combustion CO2 Capture (PC and CFB Plants).......    45
Oxy-fuel Combustion Boilers......................................    46
CO2 Transport and Geologic Storage....................    46
CCS in the United States.........................................    47
CO2 Transportation....................................    49
Policy-related Long-term CO2 Storage Issues...........    49
Long-term CO2 Storage Liability Issues................    49
RD&D Investment for Advanced Coal and CCS Technologies...........    49
Prepared Statement of Dr. Gerald H. Groenewold, Director, Energy 
  & Environmental Research Center, University of North Dakota....    62


 CLEAN COAL, OIL AND GAS DEVELOPMENT, NEW ENERGY OPPORTUNITIES THROUGH 
                       CARBON CAPTURE AND STORAGE

                              ----------                              


                        MONDAY, AUGUST 13, 2007

                               U.S. Senate,
      Subcommittee on Energy and Water Development,
                               Committee on Appropriations,
                                                      Bismarck, ND.
    The subcommittee met at 9:38 a.m., in the Pioneer Room, 
State Capitol Building, Hon. Byron L. Dorgan (chairman) 
presiding.
    Present: Senator Dorgan.


              opening statement of senator byron l. dorgan


    Senator Dorgan. I call the hearing to order. This is a 
hearing of the Senate Energy and Water Development 
Appropriations Subcommittee. The hearing subject is clean coal, 
oil and gas development and new energy opportunities through 
carbon capture and storage.
    I'm Byron Dorgan, chairman of this Appropriations 
subcommittee. The ranking member is Senator Domenici from New 
Mexico, who is not able to be with us today, but I'm pleased 
that Franz Wuerfmannsdobler is here. Franz is a principal 
staffer on our Energy and Water Subcommittee dealing 
principally with energy issues.
    I want to thank all of you for coming. This is a very 
interesting subject, and I want to make just a couple of 
comments as we begin and then I will call on a number of 
witnesses.
    We're talking a lot about energy independence these days 
because we are, in my judgment, dangerously dependent on 
foreign sources of oil. Sixty percent of our oil comes from 
outside of our country, much from troubled parts of the world. 
If, God forbid, something should interrupt the oil pipeline 
tomorrow morning from Saudi Arabia, Venezuela, Iraq, or you 
name it, our economy, our country, would be in very serious 
trouble. And because we are dangerously dependent on foreign 
sources of oil, we're talking about how we become less 
dependent and, therefore, identify the domestic resources we 
can use to become less dependent.
    We have abundant resources of fossil fuels, coal, oil, and 
natural gas. We have substantial opportunities in renewable 
fuels and we're going to do much more in all of these areas. 
There's a lot of talk about renewable fuels, and we know that 
we're doing a lot on wind energy in North Dakota, which I've 
supported for a long while. We're seeing ethanol plants being 
developed and biomass as well; we're seeing a lot of new things 
happening in the renewable fuels area.
    But this should not suggest that we are not going to use 
our fossil fuels. We are. I don't think anyone believes that 
somehow in a short, intermediate or long term that we're not 
going to continue to use fossil fuels. The question isn't 
``whether.'' The question is under what conditions we use them.
    And I say that because these days things have changed with 
respect to those calculations. Now you can't discuss these 
issues without discussing climate change in the same breath. 
We've come to an intersection where the issue of climate change 
relating to energy production and the use of energy is a 
significant part of many future policy discussions, and so 
we'll be talking about that today.
    We're now seeing some of the highest prices for oil and 
gasoline that we've seen in the history of this country. We 
know that 80 to 90 percent of the proven oil reserves on this 
Earth of ours are controlled by entities owned by foreign 
governments--let me say that again, 80 to 90 percent of the 
known and proven reserves are owned by entities or controlled 
by entities that are owned by foreign governments. That's an 
important thing to understand in terms of the geopolitics of 
our planet.
    We stick little straws in our planet and we suck oil out of 
this planet that we live on. We suck out about 84 million 
barrels a day, and we use one-fourth of that here in the United 
States of America, about 21 million barrels a day. So we take 
out about 84 million barrels every day out of this planet. We 
have a prodigious appetite for it here in the United States of 
America. Saudi Arabia has what we think to be the world's 
largest reserves of oil, 265 billion barrels, but it is not 
clear that that's a good number. It's just the best number 
people have. And as I said, 265 billion barrels--not million, 
billion barrels.
    In the history of oil production in our country, since we 
started producing oil and discovered oil, we've produced about 
195 billion barrels of oil in the United States, and reports 
indicate that there are about 20 billion barrels that are 
estimated reserves in this country at the moment. We also hear 
that, even though those are the reserves that are estimated, 
there are about 200 billion barrels more that remain residually 
in geographically complicated, partially produced or perhaps 
even mature oilfields that are potentially achievable; that is, 
it exists, but is residual oil that is not pulled up under 
normal oil drilling circumstances. Why is that important? Why 
have I described that? Because we're also going to use coal in 
the future.
    I have been working on this subcommittee to invest in 
research for coal development. I have increased substantially 
the President's request for that research. The President has 
talked a lot about research, but had not quite the appetite to 
ask for the funding for it, so Senator Domenici and I 
substantially increased funding because we know this Nation is 
going to use fossil fuels. The question is how. And research to 
unlock the opportunities, for example, to have coal-fired 
generating plants that are zero-emission plants is research 
that, I believe, is very important to the future of this 
country.
    But we also know that in the process of developing various 
types of energy, particularly in the area of coal-based energy, 
there are greenhouse gases that are emitted, CO2 
primarily, and we know that there is a climate change issue 
that our country and the world is now concerned about. We also 
understand that with the largest reserves of coal, somewhere in 
the neighborhood of 200 years, perhaps much, much more than 
that, worth of coal at the current usage rates, we must 
continue to unlock the ability to use that coal without 
injuring our climate.
    And one of the ways to do that, I believe, that we've been 
discussing in our committee and funding research of, is to 
capture the carbon in coal-fired plants and sequester it in oil 
wells, which may enhance oil recovery. And when oil is $60, 
$70, $75 a barrel, the ability to use a product that you need 
to capture and contain anyway for beneficial use in an oilfield 
gives you the opportunity to help pay for the cost of capture. 
We could enhance substantial oil recovery and protect the 
environment, even as we continue to substantially use the coal 
resource that's in such abundant supply.
    These issues kind of relate and we're trying to determine 
through research what we can do, how we can do it, what is 
commercially capable now, what we think might be commercially 
capable with the use of new research and technology later. I 
won't quote former Secretary of Defense Rumsfeld about what we 
don't know, what we don't know what we don't know, and he went 
on and on at length, but there's a lot we don't know. Some we 
do know. And as we follow the trail, follow the clues that lead 
us to believe that, through technology and research, we can 
continue in a very significant way to use our most abundant 
resource--fossil fuels--innovatively, by using the product of 
carbon that is produced in a beneficial rather than detrimental 
way, that could prove dramatic for this country's energy 
future.
    I want our State to be a leader in this area. We have 
greater capability than, I believe, any other State in this 
country. We have abundant coal and we have substantial oil. I 
should mention to all of you that the U.S. Geological Survey 
has indicated to me that in early 2008 the Dr. Price study will 
be redone and we will know then what our Bakken shale potential 
is. If it is anywhere near what someone suggested it was we are 
on the threshold of substantial opportunities in oil 
development. And, in addition to that, we have opportunities in 
virtually every other form of energy production. Very few 
States--perhaps no State--has a greater capability than we do, 
and that's why I'm excited about this. Producing energy for a 
hungry country and world is a very important thing to do. 
Energy production would enhance our economy, but also, if we do 
it the right way, contribute substantially to the well-being of 
our country.
    So we have a number of people here today. I want to just 
say, as I introduce those who will be testifying that there's a 
lot of good work going on in North Dakota. We've got 
interesting things happening already, and have for some long 
while. We have the only coal gasification plant in the 
country--synthetic coal gasification plant. We've learned a lot 
from that and are still learning from it. We've got a lot of 
other inventive and interesting endeavors here; for instance 
what I think, is the world's largest CO2 capture 
project that pipes in to Canada for enhanced oil recovery. 
That's the Basin Electric project. So there's a lot going on. 
We've got a lot of other people that are engaged in new, 
interesting projects that can significantly enhance our energy 
future as well.
    So I thank all of you for coming and being a part of this. 
I want to introduce the first witness, Carl Bauer, the Director 
of the National Energy Technology Laboratory. Carl is someone 
who has a substantial relationship with the Senate Energy 
Committee in the sense that we call on him a lot for testimony 
and rely a lot on substantial cutting-edge research being done 
by him and the people who work at his national laboratory.
    Carl, welcome to North Dakota. Thank you very much and you 
may proceed.
STATEMENT OF CARL O. BAUER, DIRECTOR, NATIONAL ENERGY 
            TECHNOLOGY LABORATORY, DEPARTMENT OF ENERGY
    Mr. Bauer. Thank you, Chairman Dorgan. I appreciate the 
opportunity to provide testimony on DOE's advanced clean coal 
technologies and the program for carbon capture and storage.
    The economic prosperity of the United States over the past 
century has been built upon an abundance of fossil fuels. 
Making full use of this domestic asset in a responsible manner 
will enable the country to fulfill its energy requirements and 
its obligation to its people in the century ahead.
    Given current technologies, coal prices, and the rate of 
consumption, the United States has approximately a 250-year 
supply of coal available.
    The Nation is also the home to a large resource of oil. We 
have currently proven reserves--and I'm kind of rehashing what 
you've already said, Senator, but I'll just go on with it--22 
billion barrels. A recent study by Advanced Resources 
International for DOE identified 390 billion barrels of oil 
remaining in place after current production methods. The 
instrument that more than 40 billion barrels could be made 
economic if ready supply of low-cost CO2 was 
available and improved, technology for enhanced oil recovery 
was applied. There is a growing consensus that increased level 
of greenhouse gas emissions are linked to climate change, and 
fossil fuel use has been identified as a major source of these 
emissions, particularly of CO2.
    Slowing the growth of these emissions has become an 
important concern and both of these challenges, developing 
domestic sources of fossil fuels and reducing the emissions of 
CO2 from coal-fired power plants, can be addressed 
through the use of captured CO2 for enhanced oil 
recovery. While not the complete solution to either of these 
challenges, incremental oil produced from such applications 
could help offset the initial cost of CO2 capture 
and storage. The prospect of low-cost supplies of captured 
CO2 could provide the impetus for a national 
reevaluation of the EOR potential in many of the mature fields. 
Continued evolution of enhanced oil recovery and advances in 
developing and deploying CO2 captured from coal 
power could help realize this synergy between the coal and 
power industry and the oil industry.
    Though the challenges are significant, the United States is 
well positioned to capitalize on these synergies. Past DOE-
funded research helped advance industrial enhanced oil recovery 
operations. Today the focus is on the carbon captured storage 
side problem. To date, for 35 years of enhanced oil recovery, 
only 1 billion barrels have been produced through the use of 
CO2 EOR, so there's a great opportunity for a lot 
more oil to come forward.
    The Office of Fossil Energy's coal R&D program provides for 
the development of new environmentally responsible, cost-
effective approaches to coal use. It includes technologies that 
will either facilitate the efficient capture of CO2 
from the coal-fired plants for subsequent sequestration or 
directly address the solutions for safe and permanently 
sequestering it in the underground reservoirs. Details of these 
programs are in my written testimony.
    With the core coal R&D program, the Carbon Sequestration 
Regional Partnership, of which North Dakota is one of the 
leaders, have brought an enormous amount of capability and 
experience together to work on the challenges of both 
infrastructure development and stored underground carbon. The 
partnerships are conducting field tests to validate the 
efficacy of carbon capture and storage technologies in a 
variety of geological and terrestrial storage sites throughout 
the United States and Canada. We are working with North 
Dakota's Energy & Environmental Research Center on the Plains 
CO2 Reduction Partnership, which is defining the 
potential of sequestration in North Dakota, South Dakota, and 
in Alberta, Canada. EERC is also addressing issues related to 
low-rank subbituminous and lignite coal utilization.


                           prepared statement


    Developing the technologies needed to support a widespread 
expansion of CO2 EOR could substantially increase 
existing U.S. reserves and production. The DOE's efforts are 
providing the elements needed to enable this expansion by 
advancing capture technologies to ensure a reliable low-cost 
supply of CO2 and improved EOR technologies to 
optimize for carbon sequestration co-benefits.
    Mr. Chairman, this completes my statement. I would be happy 
to take any questions you have.
    [The statement follows:]
                  Prepared Statement of Carl O. Bauer
    Thank you Mr. Chairman. I appreciate this opportunity to provide 
testimony on the Department of Energy's advanced clean coal 
technologies and the program for carbon capture and storage.
    The economic prosperity of the United States over the past century 
has been built upon an abundance of fossil fuels in North America. The 
United States' fossil fuel resources represent a tremendous national 
asset. Making full use of this domestic asset in a responsible manner 
enables the country to fulfill its energy requirements, minimize 
detrimental environmental impacts, and positively contribute to 
national security.
    Given current technologies, coal prices, and rates of consumption, 
the United States has approximately a 250-year supply of coal 
available. Coal-fired power plants supply about half of our electricity 
and are expected to continue to do so through mid-century. Because 
electricity production increases at a rate of about 2 percent per year, 
the rate of coal use will increase proportionally. However, the 
continued use of this secure domestic resource will be dependent on the 
development of cost-effective technology options to meet both economic 
and environmental goals, including the reduction of greenhouse gas 
emissions.
    The Nation is also home to a large resource of oil. Although much 
of the Nation's onshore petroleum resource has been produced, large 
volumes of crude oil remain in place after current production methods 
are exhausted. These resources are being held in place by physical 
forces or left behind due to geologic complexity being both 
economically and technologically challenged. The total volume of this 
stranded oil is estimated by Advanced Resources International (ARI) of 
Washington, DC, to exceed 390 billion barrels, of which roughly 200 
billion barrels are estimated to be relatively accessible at depths of 
up to 5,000 feet but do not have CO2 available for EOR. To 
put these numbers in context, according to the Energy Information 
Administration (EIA), we have produced about 195 billion barrels of our 
petroleum resource over the past 120 years and currently have proven 
reserves of roughly 22 billion barrels (source: EIA online database, as 
of December 2005, crude oil, does not include natural gas liquids).
    Currently, there is growing consensus that increased levels of 
greenhouse gases in the atmosphere, primarily carbon dioxide, methane, 
nitrous oxide, and chlorofluorocarbons, are linked to climate change. 
In this connection, fossil fuel use, in general, and coal-fired power 
plants, in particular, have been identified as a major source of 
anthropogenic greenhouse gas emissions, particularly carbon dioxide, 
into the atmosphere. Slowing the growth of anthropogenic greenhouse gas 
emissions has become an important concern.
    Both of these challenges--developing domestic sources of fossil 
fuels and reducing emissions of carbon dioxide (CO2) from 
coal-fired power plants--can be addressed simultaneously through the 
use of captured CO2 for enhanced oil recovery (EOR). While 
not the complete solution to either of these challenges, incremental 
oil produced from such applications could help offset the costs of 
CO2 capture, while the prospect of low-cost supplies of 
captured CO2 in widespread areas of the country could 
provide the impetus for a national re-evaluation of the EOR potential 
in many mature fields. While EOR is a mature technology that has been 
in commercial use for decades, CO2 capture from coal power 
is not yet commercial. Continued evolution of EOR and transformational 
advances in development and deployment of CO2 capture from 
coal power could help realize this synergy between the coal/power 
industry and the oil industry.
                 how is doe responding to these issues?
    While the challenges are significant, the United States is well 
positioned to capitalize on these synergies. The oil industry has been 
using CO2 for EOR in commercial applications for decades. As 
early as the 1970s, DOE-funded projects were assessing the fluid 
properties of CO2 to establish its applicability in EOR. A 
special focus was given to developing correlations that helped the oil 
industry utilize these properties to optimize commercial EOR projects. 
During 1993-2003, DOE funded nearly half of the $100 million spent on 
the Class Program CO2-EOR Field Demonstration Projects in 
six States. Approaches included the use of horizontal wells for 
improved reservoir contact, four-dimensional seismic to monitor the 
behavior of CO2 floods, automated field-monitoring systems 
for detecting problems, and the injection of increasingly larger 
volumes of CO2 to increase recovery rates. In summary, this 
DOE-funded research has helped advance industrial EOR operations, but 
the focus is now on the carbon sequestration side of EOR, which is a 
developing technology, rather than the oil production side of EOR, 
which is a mature technology. DOE-funded research continues to include 
some research on EOR.
    The Office of Fossil Energy's core coal R&D program provides for 
the development of new cost- and environmentally-effective approaches 
to coal use. It includes technologies that will either facilitate the 
efficient capture of CO2 from coal-fired plants for 
subsequent sequestration or directly address solutions for safely and 
permanently sequestering it in underground reservoirs. These programs 
include gasification, advanced turbines, fuel cells, FutureGen, and 
carbon sequestration, and are described in more detail below.
Gasification
    Gasification is a pre-combustion pathway to convert coal or other 
carbon-containing feedstocks into synthesis gas, a mixture composed 
primarily of carbon monoxide and hydrogen; the synthesis gas, in turn, 
can be used as a fuel to generate electricity or steam, or as a basic 
raw material to produce hydrogen, high-value chemicals, and liquid 
transportation fuels. DOE is developing advanced gasification 
technologies to meet the most stringent environmental regulations in 
any State and facilitate the efficient capture of CO2 for 
subsequent sequestration--a pathway to ``near-zero atmospheric 
emissions'' coal-based energy. Gasification plants are complex systems 
that rely on a large number of interconnected processes and 
technologies. Advances in the current state-of-the-art, as well as 
development of novel approaches, could help reveal the technical 
pathways enabling gasification to meet the demands of future markets 
while contributing to energy security.
Advanced Turbines
    The Advanced Turbine Program consists of a portfolio of laboratory 
and field R&D projects focused on performance-improvement technologies 
with great potential for increasing efficiency and reducing emissions 
and costs in coal-based applications. The Program focuses on the 
combustion of pure hydrogen fuels in MW-scale turbines greater than 100 
MW size range and the compression of large volumes of CO2. 
Since advanced turbines will be fuel flexible, capable of operating on 
hydrogen or syngas, they will make possible electric power generation 
in gasification applications configured to capture CO2.
Fuel Cells
    Fuel cells could help support the efficiency and emission targets 
of future power plants, such as FutureGen. In order to ensure the 
ability to site future power plants in any State in the country, low 
emissions of criteria pollutants will be required. Fuel cell emissions 
are well below current and proposed environmental limits. Their modular 
nature permits use in central or distributed generation with equal 
ease. Rapid response to emergent energy needs is enhanced by the 
modularity and fuel flexibility of fuel cells. The ultimate goal of the 
program is the development of low-cost large (>100 MW) fuel cell power 
systems that will produce affordable, efficient, and environmentally 
friendly electrical power from coal with greater than 50 percent higher 
heating value (HHV) efficiency, including integrated coal gasification 
and carbon dioxide separation processes that capture at least 90 
percent of the CO2 emissions from the system. The cost goal 
for fuel cells in coal systems is to achieve a ten-fold reduction in 
the fuel cell system cost.
FutureGen
    FutureGen is a $1 billion Government-industry initiative to design, 
build, and operate an advanced, coal-based, Integrated Gasification 
Combined-Cycle (IGCC) power plant to:
  --Co-produce electricity and hydrogen;
  --Achieve near-zero atmospheric emissions, with geological 
        sequestration of carbon dioxide;
  --Demonstrate system integration of cutting edge technologies; and
  --Chart a technological pathway toward an energy future in which 
        near-zero atmospheric emissions clean coal power plants can be 
        designed, built, and operated at a cost that is no more than 10 
        percent above the cost of non-sequestered systems.
    Coal continues to face environmental challenges relative to other 
energy sources. The near-zero atmospheric emissions concept spearheaded 
by FutureGen is vital to the future viability of coal as an energy 
resource, particularly in light of growing climate change concerns. 
Coal is abundant, secure, and relatively inexpensive when compared to 
other energy sources. With near-zero atmospheric emissions, coal could 
not only produce baseload electricity, but also help germinate a 
hydrogen energy economy.
Carbon Sequestration
    The Carbon Sequestration Program consists of a portfolio of 
laboratory and field R&D focused on technologies with great potential 
for reducing greenhouse gas emissions. Most efforts focus on capturing 
carbon dioxide from large stationary sources such as power plants, and 
sequestering carbon dioxide in geologic formations. Carbon 
sequestration is a key component of the President's strategy to slow 
the growth of greenhouse gas emissions, as well as several National 
Energy Policy goals targeting the development of new technologies. It 
also supports the goals of the Framework Convention on Climate Change 
and other international collaborations to reduce greenhouse gas 
intensity and greenhouse gas emissions. The programmatic timeline is to 
demonstrate a portfolio of safe, cost-effective greenhouse gas capture, 
storage, and mitigation technologies at the pre-commercial scale by 
2012, leading to demonstration and substantial deployment and market 
penetration beyond 2012. These greenhouse gas mitigation technologies 
could help slow greenhouse gas emissions in the medium term. They also 
provide potential for ultimately stabilizing and reducing greenhouse 
gas emissions in the United States.
       opportunities for synergy between coal and oil industries
    Many EOR processes incorporating thermal, chemical, microbial, and 
a variety of miscible gas-injection methods have been employed in the 
United States. Among these, CO2-EOR is most promising and 
has in fact produced 1 billion barrels of oil to date. Because 
CO2 is miscible with crude oil under certain conditions, it 
can be injected into previously drained oil reservoirs and used to 
sweep a portion of the remaining oil from the rock, helping to overcome 
the physical forces that trap the residual oil. While not all of the 
easily accessible stranded oil is susceptible for recovery by 
CO2-EOR, a large proportion could be recovered if a source 
of low-cost CO2 and improved CO2-EOR technologies 
are developed and applied to the problem.
    A series of CO2-EOR assessments conducted for DOE's 
Office of Fossil Energy by ARI concluded that, if current high oil 
prices are sustained over the long-term, low-cost captured 
CO2 from power plants is available (at a cost of between $27 
and $34 per ton of CO2 delivered to the oil field), and 
improved CO2-EOR technology is applied which maximizes oil 
recovery while minimizing the CO2 needed, 47 billion barrels 
of incremental oil--more than twice the current U.S. reserve--would be 
economic to produce. Of course, only a few companies currently have 
access to the state of the art technology and oil companies take many 
factors into consideration when determining which investments to make. 
Therefore, even if these technological advances are made, it is 
possible that not all of the additional 47 billion barrels of domestic 
oil would be produced.
    Within just the large fields in North Dakota's portion of the 
Williston Basin, as much as 390 million barrels of incremental oil 
could have a cost of production less than the current price of oil 
under this scenario. In addition, the feasibility of converting the 
large unconventional in-place resource within the Bakken Shale of North 
Dakota into economic reserves using next generation CO2-EOR 
technology has not been examined (studies have suggested that 100 to 
150 billion barrels, or more, of resource may be in-place). However, if 
injection of CO2 into this fractured shale could mobilize a 
portion of this resource, the Williston Basin's contribution to the 
Nation's oil supply could be significantly expanded.
    In addition, while the main focus of CO2-EOR is on 
maximizing the amount of oil produced rather than the amount of 
CO2 injected, its sequestration potential is still 
significant, though much less than the sequestration potential of 
saline formations in the U.S. Estimates by Vello Kuuuskraa at ARI are 
that the technical limit for CO2 storage associated with EOR 
is 20 gigatons and that between 8-12 gigatons can be economically 
stored if next generation EOR technology is developed and applied, 
assuming that the cost of CO2 is less than $30-$38/ton 
delivered, which would require significant advances in carbon capture 
technology. To put this into context, total man-made U.S. greenhouse 
gas emissions (carbon dioxide, methane, nitrous oxide, and 
hydrofluorocarbons) in 2004 were the equivalent of about 7.8 gigatons 
of CO2 equivalent. This total includes approximately 6 
gigatons of actual CO2. About 2.2 gigatons of this 
CO2 comes from coal-fired power plants, and the balance 
(approximately 3.8 gigatons) stems from oil and gas use.
    According to the Energy Information Administration's Annual Energy 
Outlook 2007, coal-fired generation produced 84 percent of the 
CO2 associated with electrical power generation in 2006, and 
33 percent of total U.S. emission of CO2. This forecast also 
suggests that CO2 from coal-fired power generation is 
expected to represent 88 percent of all CO2 related to 
electric power generation by 2030, and 37 percent of total U.S. 
emission of CO2.
    CO2-EOR projects represent an early major opportunity 
for helping to realize carbon capture technology. This opportunity has 
unique potential to overcome economic, social, and risk obstacles 
associated with the commercialization of technology. In addition, the 
use of CO2-EOR projects could help power generation 
companies to take advantage of the oil industry's expertise with 
CO2 handling and injection, and help accelerate the 
implementation of other underground CO2 sequestration 
options in coalbeds, depleted gas reservoirs, and deep saline 
formations.
                               conclusion
    Today, nearly three out of every four coal-burning power plants in 
this country are equipped with technologies that can trace their roots 
back to the Clean Coal Technology Program. Approaches demonstrated 
through the program include coal processing to produce clean fuels, 
combustion modification to control emissions, post-combustion cleanup 
of flue gas, and repowering with advanced power generation systems. 
These efforts helped accelerate production of cost-effective compliance 
options to address environmental issues associated with coal use. 
Relative to carbon capture and storage, DOE is making significant 
progress in developing the technologies and infrastructure needed for 
deployment of these technologies in a future carbon-constrained world. 
Evidence of this progress includes:
  --The Carbon Sequestration Atlas of the United States and Canada, 
        developed by NETL, the Regional Carbon Sequestration 
        Partnerships (Partnerships), and the National Carbon 
        Sequestration Database and Geographical Information System, 
        contains information on stationary sources for CO2 
        emissions, geologic formations with sequestration potential, 
        and terrestrial ecosystems with potential for enhanced carbon 
        uptake, all referenced to their geographic location to enable 
        matching sources and sequestration sites.
  --Carbon dioxide capture technology is being developed for solvent, 
        sorbent, membrane, and oxy-combustion systems that, if 
        successfully developed, would be capable of capturing greater 
        than 90 percent of the flue gas carbon dioxide at a significant 
        cost reduction when compared to state-of-the-art, amine-based 
        capture systems. Research and systems analysis have identified 
        potential cost reductions of 30-45 percent for the capture of 
        CO2. In addition, ionic liquid membranes and 
        absorbents are being developed for capture of CO2 
        from power plants. Ionic liquid membranes have been developed 
        at NETL for pre-combustion applications that surpass polymers 
        in terms of CO2 selectivity and permeability at 
        elevated temperatures.
  --Field projects have demonstrated the ability to ``map'' 
        CO2 injected into an underground formation at a much 
        higher resolution than previously anticipated and confirmed the 
        ability of perfluorocarbon tracers to track CO2 
        movement through a reservoir.
  --The Carbon Sequestration Regional Partnerships have brought an 
        enormous amount of capability and experience together to work 
        on the challenge of infrastructure development. Together with 
        DOE, the Partnerships secured the active participation of more 
        than 500 individuals representing more than 350 industrial 
        companies, engineering firms, state agencies, non-governmental 
        organizations, and other supporting organizations.
  --The Partnerships are conducting field tests to validate the 
        efficacy of carbon capture and storage technologies in a 
        variety of geologic storage sites throughout the United States 
        and Canada. Using the extensive data and information gathered 
        during the initial stages of the project, the 7 Partnerships 
        identified the most promising opportunities for carbon 
        sequestration in their Regions and are performing 25 geologic 
        field tests.
    Developing the technologies needed to support a widespread 
expansion of CO2-EOR could substantially increase existing 
U.S. reserves and production. The DOE efforts listed above are 
providing the elements needed to enable this expansion by advancing 
capture technologies to ensure a reliable low-cost supply of 
CO2 and improved EOR technologies to optimize for carbon 
sequestration co-benefits.
    Mr. Chairman, and members of the subcommittee, this completes my 
statement. I would be happy to take any questions you may have.

    Senator Dorgan. Mr. Bauer, thank you very much. Let me 
begin by asking about the costs involved. It is one thing to 
say let's capture carbon. It's quite another thing to determine 
the impact or the cost. Will it be economically feasible to 
capture the carbon? Will this destroy projects that are on the 
drawing boards because it's just way too expensive? Are you a 
pointy-headed researcher who loves to talk in theory about 
things in practice not achievable? So tell me--well, I know 
you're not a pointy-headed researcher.
    But tell me, if you will, with what capability we can, in a 
realistic way, capture carbon and use it for beneficial use?
    Mr. Bauer. I think that's a very important comment and 
question. While we can capture--many people make the case that 
we can capture or separate CO2 today, the economics 
around it are prohibitively expensive. Just to give you a 
quick, round number, if we took the 300 gigawatts of coal-
powered generation today and said that 50 percent of it was 
going to have to be--of the CO2 produced would have 
to be captured and done away with, put in the ground, that 
would increase the price of electricity from an average of $25 
a megawatt for those plants to almost $80 a megawatt. That's a 
substantial increase. It would reduce the power delivered by 
about 42 gigawatts. That's about a 15 percent reduction. Or to 
put it in other terms, we would have to find 42 gigawatts of 
additional electricity to make up for the electricity utilized 
in the carbon capture and storage. So while we can do it, the 
potential impacts are substantial.
    To give you a perspective, a megawatt of natural gas right 
now is about $65 a megawatt, in round numbers. So right now 
coal is keeping the price of electricity down, and nuclear 
power also contributes to that. This would raise the price. But 
if we were to say we would offset that 42 gigawatts by an 
additional use of natural gas, we would have to find for every 
25 gigawatts of additional natural gas, 1 trillion cubic feet 
of additional natural gas supply, which is already a challenge 
to the United States in that we import about 18 percent of our 
natural gas, and we would have to substantially increase that 
number to meet that additional. Or another way to think about 
it, the Alaskan Pipeline for natural gas is about 1.6 trillion 
cubic feet a year of natural gas when it's in place, so we are 
looking at one and a half natural gas pipelines just to make up 
for that CO2 cost right now.
    Senator Dorgan. Are there some applications from which it 
is harder to extract and capture CO2 than others, 
and, if so, what are they?
    Mr. Bauer. At present most of our coal fleet is a 
pulverized coal combustion-type fleet, and the flue gas that 
comes out of those combustion plants is very dilute, and so 
it's much more difficult to capture CO2 from this 
juncture. Dakota Gasification is a gasifier. It converts coal 
into a synthetic gas. Methanization makes it pipeline grade 
natural gas equivalent. Right now that CO2 is at a 
higher concentration, so that's more readily separable and a 
better economic perspective and, therefore, it looks like now 
that those plants have a slight advantage on price in dealing 
with CO2 in complexity.
    There are technologies coming forward that look at using 
more oxygen and less air in firing pulverized coal plants, 
which would increase the concentration of CO2, but 
those are probably 8 to 10 years from real commercial 
application.
    Senator Dorgan. Describe for me the work, if any, that you 
have done on lignite coal.
    Mr. Bauer. We've done quite a few different kinds of work 
on lignite coal, everything from--and, in fact, EERC has been a 
major partner in some of that. We're looking at the transport 
gasifier. It's a different version of gasification. And it's 
almost like a fluidized bed coal plant. It moves the coal 
through the system and it works to the advantage of the 
lignite-type and Powder River Basin-type coal for its 
utilization. We've worked on environmental separation of 
mercuries and other emissions from the coal. There's been work 
with Basin Electric actually in drying lignite coal, which has 
high water content, and that reduces the energy penalty on 
that. And some of the Clean Coal projects that have gone 
forward have demonstrated these technologies at a reasonable 
scale for them to go to commercial application. I believe they 
are going to commercial application.
    Senator Dorgan. In your judgment, what's the highest valued 
and best use of lignite coal?
    Mr. Bauer. I think the best use for lignite coal is a 
combination of either electricity production, as it has been 
used to a large degree, or gasification, as the Dakota 
Gasification Plant has proven is possible and commercially 
viable, possibly even using it for a source of feedstock for 
coal-to-liquids, azeotrope-type liquids, which are a diesel-
type liquid, or even potentially to gasoline product. And with 
the price of oil per barrel and the high concentration of 
CO2, I think they're a viable possibility that it 
could still compete readily in the marketplace with 
CO2 as a product that has to be dealt with either by 
way of a product or as a way of a waste.
    Senator Dorgan. Lignite coal, to our chagrin, is sometimes 
referred to as a low-rank coal.
    Mr. Bauer. Yes, sir.
    Senator Dorgan. Describe for me, if you could, in terms of 
the other uses, the uses other than producing electricity, 
coal-to-liquids, coal-to-synthetic gas, coal-to-plastics, and 
so on, the advantages and disadvantages of lignite coal versus 
other kinds of coal in those processes?
    Mr. Bauer. The reason lignite coal is called low rank is 
not to imply a value statement, but it's to recognize that 
bituminous coal is about 13,000 BTUs per pound and lignite coal 
is about 8,500 BTUs per pound, so it's just relative per-pound 
BTU value. If you go to use lignite for a nonelectrical 
application, probably the way one would use it would be to 
gasify it, which is not to burn it, but to put it in an 
atmosphere and cause it to kind of give off its value in a 
gaseous manner. It's still a thermal conversion process. What 
comes off is largely carbon dioxide, carbon monoxide and 
hydrogen. You would take and reform it by pressing steam 
through it to shift the CO to carbon monoxide into additional 
carbon dioxide and form more hydrogen so that you would have a 
synthetic gas that comes out of the other side and you could 
either increase the gas into a methane, a natural gas-type 
product, or you could take the feedstock and the hydrogen and 
use it in chemical processes and applications, or you could 
take the synthetic gas and go through a catalytic conversion 
and make a gasoline or a diesel-type product, azeotrope process 
that normally calls for diesel. The other thing you can do with 
it is to burn it and make electricity out of the hydrogen, and 
the CO2 is a high concentration so it's readily 
stripped off.
    Now, that is all in theory and pilot scale practice. The 
CO2 issue I, personally, think is more readily dealt 
with, but there's still an economic challenge, a balance and 
plant challenge in doing that that we haven't been able to do 
at a large scale, other than what we've learned at Dakota 
Gasification, which, as you pointed out, is a major source of 
insight on the dynamics of doing that.
    Senator Dorgan. My understanding is, and I'll ask Ron 
Harper about this when he testifies, that we capture about 50 
percent of the CO2 from Dakota Gasification, and 
furthermore that, much like other applications in these coal 
plants, as you incrementally capture more and more 
CO2, the more costly it is per unit of collection. 
Is that the case with CO2 in most cases?
    Mr. Bauer. The issue for CO2 is the higher you 
go, the harder it is to separate what's left out of the--
without taking other fuel beneficial. So, for example, if you 
try to push the limit up towards 90 or 100 percent, you're 
going to wind up taking away some of the high-value hydrogen 
with the CO2 and losing its use or its availability.
    On Dakota Gasification, I think it's important to remember 
Dakota Gasification was not initially designed to be a 
CO2 separation and synthetic gas, and so backfitting 
to separate the CO2 has certain drawbacks or lack of 
ability to optimize, and if the plant were designed from 
today--and I'm sure Ron can either clarify or correct me--you 
might not do it exactly the same way or you designed it to be 
more efficient, but still, having said that, the higher you go, 
the more difficult it becomes and, therefore, the more 
expensive.
    Senator Dorgan. Congress is going to make the judgments 
ultimately about policy, but you are providing your research 
reports to Congress and your best advice. We talked earlier 
about the economics of it. What do you think is achievable in 
various applications? And, you know, one of the things that 
we've discussed previously is that people who have projects in 
mind at this point face uncertainty. They don't know what the 
rules might be. They don't know what the carbon capture 
requirement will be. They know there will be rules, but they 
don't know what they will be or over what timeframe or what 
costs might apply to their projects. What kinds of thoughts do 
you have about how policymakers should establish the framework 
here? How should Congress establish that framework?
    Mr. Bauer. Well, as you mentioned, Senator, I'm not 
supposed to be in the policy business. I can only give a 
technical and possibly some minor economic perspective. I think 
if we look at the Clean Air Act as some indicator of what it 
takes to get to some regulatory structure for business 
decisions to be made, you're talking from the time of final 
legislation to actually the publication of regulation and rules 
against which decisions are made so they have to meet these 
requirements or be found in violation. It can be an 8- to 10-
year process to get through the publication of regulations, the 
bidding of them, and even the challenges in court before we 
come out the other end with an area of certainty.
    I do know, though, that the regulations for use of EOR 
exist. So using CO2 in EOR process, we believe that 
our indications of the numbers are that, you know, there's 15 
to 20 years that EOR could utilize most of the CO2 
that's generated in this country if it were made available to 
the various sites. If you look at enhanced oil recovery sites, 
most of them are done in the western Texas, southeastern New 
Mexico area largely because there's a lot of naturally 
occurring CO2 out there that they tap and release 
from the ground and use it to do EOR. If there were an 
anthropogenic, manmade CO2 readily available in 
quantity and at a reasonable price, and that's where Dakota 
Gasification is a model, that's why the Saskatchewan oilfields 
buy their CO2, they can get it at a competitive 
price that makes it a very viable source of EOR for them, 
they'll take as much as they can give them right now, then it 
makes a different dynamic.
    So one thing we might be thinking about as we're trying to 
deal with the CO2 issue, the greenhouse gas issue, 
how do we recognize the value of EOR in a way that stimulates 
coal-powered generation, coal gasification liquids to utilize 
that as a means for the first decade of the plant's operation 
without having to worry about the significant challenges of 
storage and liability and long-term storage, and what are the 
Federal, State and local issues and regulations required for 
them to make a business decision. So that might be a way 
forward at least to provide some near-term certainty.
    Senator Dorgan. Your principal research is in the area of 
coal, and yet in your testimony both before the Congress and 
also at this hearing about the beneficial use of 
CO2, you're talking about enhanced oil recovery. 
Your research includes that?
    Mr. Bauer. Yes. Our research really is all fossil fuels, 
and actually we do some in the area of biomass and renewables.
    Senator Dorgan. Let me ask--you know, the room is not 
exactly full of people from the oil industry. And oil is at $73 
a barrel this morning.
    Mr. Bauer. Right.
    Senator Dorgan. Following your testimony before the Energy 
Committee a while back, it seems to me that if, at $73 a 
barrel, you can effectively capture CO2, use it for 
the beneficial purpose of enhancing oil recovery, it certainly 
should be attractive. What's your experience with respect to 
the oil side of this? We've been talking about the coal 
industry, but what about the oil industry? Are they interested, 
excited? Tell me about your work with them.
    Mr. Bauer. Well, I think it depends on the company really 
and the geographical region that you're talking. If they're in 
a region where they have potential oilfields that need 
CO2 to further produce, at this present value of a 
barrel of oil at $70, $74 per barrel, they would love to 
produce more oil from those fields, and if they don't have a 
CO2 source handy, they're very interested in finding 
one if the economics around it are meaningful.
    One of the problems sometimes is the utility that has the 
CO2 possibly has to actually backfit their plant to 
put the capture technology on. That can be quite expensive. 
We're not talking about millions or tens of millions.
    We're talking about maybe $200 or $300 million to put on a 
separation technology depending on the scale of the plant, but 
you would want a larger-scale plant to offset the cost, and 
then you have to move it over there, so one of the wrestling 
issues is who pays for the capture, who pays for the pipeline. 
If you look at the requirements now, I think it would be 
difficult for a utility to go before their utility commission 
board and ask to build that into their rate base case with no 
law requiring them to do that. So, unless they could show that 
the economics make sense, they may have difficulty with that, 
or the same thing from the standpoint of their investors or if 
it's an independent electricity producer.
    Senator Dorgan. But at $73-a-barrel oil--you indicated you 
think there's 200 billion barrels of oil, potentially 
recoverable over time, that's residual in the pools?
    Mr. Bauer. Let me just clarify that.
    Senator Dorgan. Clarify that, if you would.
    Mr. Bauer. There's 200 billion barrels. However, those may 
be technically recoverable but not economically viable. That's 
one of the problems right now. A reason we've only done a 
billion barrels of EOR is in many cases it's not economically 
viable. The price of the CO2 or the ability to get 
it to where it's located offsets the potential profitability.
    Senator Dorgan. What are they recovering in Canada with the 
CO2? Do you know? Probably Ron does.
    Mr. Bauer. I think they're doing about 5,000 barrels a day, 
so that's very nice when you think of the price right now, and 
Ron knows better than I what the price of CO2 is, 
but my understanding is it's very competitive in the 
CO2 marketplace right now. CO2 down in 
West Texas is going for about $20 a ton. So it's probably less 
than that in certain areas, and from a plant that would 
probably be a high number right now, if anybody would be 
willing to pay more than that, and you've got to figure the 
cost of separation equipment and the movement of the 
CO2 to the site that it would use. So I think 
there's a lot of need to foster the dynamics between the 
utility and the potential oilfield user to encourage that.
    Senator Dorgan. Is the location of our coal fields in North 
Dakota, the Fort Union Basin and so on, relative to the oil 
activity that goes on in North Dakota and Montana--I assume 
that's beneficial in terms of some future construct of using 
CO2 capture for enhanced oil recovery?
    Mr. Bauer. I think that could be very possible. And I think 
what would have to be set up would be the infrastructure to 
move the CO2 from those plants to the fields, which 
I don't think is a great technical challenge, but someone has 
to decide the business opportunity makes sense or someone wants 
to foster that. And the same thing I think in the Montana, 
Wyoming oilfields. I know the State of Wyoming has been very 
interested in talking about those things, too.
    Senator Dorgan. Franz, do you have any questions?
    Mr. Wuerfmannsdobler. Mr. Bauer, if we were to set aside 
the question of funding levels, what is the most critical 
technology or program type of activity that you think would be 
necessary to more substantially move forward so we can prove 
some of these technologies out so they could be commercially 
viable, say, within 5 to 10 years?
    Mr. Bauer. There are two, what I would suggest, major areas 
of high cost. One is the actual separation or capture of the 
CO2. As the Senator mentioned, there has been an 
increase in the Senate mark, and also the House actually 
recognized the capture challenge that would go a long way to 
moving forward more aggressively to take pilot scale or 
laboratory scale--not necessarily our laboratory, by the way--
across the country, capture technology up to the point where 
they could be commercially viable within the next decade or 
less. That would be tremendously helpful, because at the 
present previous funding we're probably 20 years away.
    The other is doing large-scale evaluations and 
demonstrations of putting a million ton-plus of CO2 
into the ground. Again, the committee's work and recent funding 
there, I think, makes that more probable in the near term, and 
that's where we're working with the regional partnerships--
there's several regional partnerships, each of them, beginning 
next year to be headed towards sticking a million tons of 
CO2 into storage reservoirs to confirm what the 
science says and the oil experience tells us is a viable place 
to store CO2 long term indefinitely. That will take 
probably 7 or 8 years before we go through the full cycle of 
setting up testing, injecting the CO2, monitoring 
and further study and analysis for a couple years to confirm 
our results.
    So those are two major areas. I think another area, though, 
which is maybe less expensive, but maybe makes it more 
challenging, is for the general public and population, local 
regulators, to understand the viability of carbon storage in 
reservoirs so that they would accept it and the permitting 
process would be a reasonably standard process and a high 
confidence that no one would be in any way harmed or threatened 
by what was done there, and that will take some funding to 
provide the opportunities to provoke participation and 
education of those who have to be involved in that process and 
the surrounding public to be fully informed and given a chance 
to work through what does that mean to them.
    Mr. Wuerfmannsdobler. Are there any other issues that you 
think would be beneficial so that the general public would 
better understand or the interested industries would better 
understand the opportunities here?
    Mr. Bauer. I think with the--in the last year especially, 
the discussion around greenhouse gas has begun to get people to 
be paying attention to what are the alternatives, what can we 
do about it. I think more information in, what I would say, a 
comprehensible manner. As you mentioned, us pointy-headed R&D 
folks sometimes talk in ways that we assume will probably make 
sense, and I'm sometimes told at home I don't make much sense. 
But, at any rate, that the public could understand the 
magnitude of this challenge and the magnitude of the threat, 
quite frankly, to their own energy and the Nation's energy 
security. I don't think that's really comprehended. So 
providing a way to communicate that in a balanced manner 
because, while I support energy from all sources, I believe our 
answers come from all energy sources, I think we need to 
honestly understand what each source has the high potential 
contributing and the more pragmatic actuality of contributing. 
And so trying to put all our eggs in any one basket is not a 
good answer, but trying to find a balance--and I know that's 
what you're working on, Senator, and Senator Domenici, as 
well--a balanced portfolio of technologies to contribute to the 
energy future of this country in an economically acceptable 
way, I think is important for our public to understand. I don't 
think they really understand it the way they should.
    Senator Dorgan. I think that's an important point. I'm a 
strong supporter of renewable energy--all kinds of renewable 
energy, but that doesn't mean we're not going to need to use 
fossil fuels in our future. We are. The question is not 
whether. The question is how do we use those, and that's why 
this research is critical.
    What I would like to do, Mr. Bauer, is, with your 
permission, call up the second panel. I would like you to, if 
you would, take a chair at the end of table and be available 
for questions that might be raised by the other panel. We 
appreciate your work at the National Laboratory and appreciate 
your being willing to come here to North Dakota this morning.
    I want to also mention that Roger Johnson, the State 
Agriculture Commissioner, is here with us and Susan Wefald, the 
Public Service Commissioner. Where is Susan?
    Ms. Wefald. Right here.
    Senator Dorgan. Thank you for being with us. If I'm missing 
somebody, let me know. Thank you for being with us. I know both 
the Agriculture Commissioner, serving on the Industrial 
Commission, and the Public Service Commission have very 
significant interests in both of these issues, and I appreciate 
both of you being at this hearing.
    Next I would like to call Ron Harper, the chief executive 
officer of Basin Electric Power Cooperative, to come up; John 
Weeda, John is the plant manager of the Coal Creek Station at 
the Great River Energy Company; Rod Nelson, vice president, 
Schlumberger Limited, on behalf of the National Petroleum 
Council; and Jeffrey Phillips, the program manager, Electric 
Power Research Institute. Mr. Harper and Mr. Weeda are both 
with us from North Dakota, and my understanding is, Mr. Nelson, 
you're from Texas.
    Mr. Nelson. Right.
    Senator Dorgan. And, Mr. Phillips, you have come to us from 
New York City.
    Mr. Phillips. Charlotte, North Carolina.
    Senator Dorgan. Charlotte, North Carolina, big difference, 
sorry about that. Accept my apologies.
    Let me turn to you, Mr. Harper. Thank you for being here 
and, as with all of you, your complete statements will be made 
a part of the permanent record and you may summarize those as 
you wish.
STATEMENT OF RONALD R. HARPER, CHIEF EXECUTIVE OFFICER 
            AND GENERAL MANAGER, BASIN ELECTRIC POWER 
            COOPERATIVE
    Mr. Harper. Thank you, Senator, and I very much appreciate 
on behalf of Basin the opportunity to come before this 
committee to talk about some critically important, what we 
believe is our future, with respect to energy development.
    Senator Dorgan. Can you pull that microphone a little 
closer so that we can hear you better? Thank you.
    Mr. Harper. Is that better?
    Senator Dorgan. Yes, much better.
    Mr. Harper. I would like to put three bullets or stakes in 
the ground. First of all, many throughout the electric industry 
are in the process of developing coal-based plants to meet this 
growing economy's need, and in the coming years we have to 
figure out how to utilize these plants more efficiently with 
respect to greenhouse gases. The second point is we strongly 
believe that coal must remain a viable part of this country's 
energy future. And, lastly, the Federal Government needs to 
undertake an aggressive strategy to mitigate the risk of a 
carbon-constrained future while at the same time balancing the 
needs of our growing economy.
    Basin believes that we are on the threshold of tremendous 
opportunity with respect to continuing the use of fossil fuels 
in this country. Technology must, however, be developed to use 
this resource much more wisely and efficiently, including 
addressing how to capture carbon dioxide. The Energy Policy Act 
of 2005 was a step in the right direction by providing tax 
incentives, loan guarantees and other programs to encourage the 
commercial development of the next generation of clean coal 
technologies.
    Much has been said already this morning about the Dakota 
Gasification project, the Great Plains Synfuels Plant, and we 
believe that has been the step to this future and how we might 
manage in a carbon-constrained environment.
    As was mentioned by the earlier presenter, we are a major 
player in the Plains CO2 Reduction, or PCOR, 
Partnership. We are also involved in the Canadian Clean Coal 
Power Coalition. But, more importantly, we are doing it. We are 
capturing carbon and providing sequestration opportunity in the 
Canadian oilfields. We have so far sequestered 10 million tons 
of CO2, and it is our belief that the CO2 
is being permanently sequestered in those oil fields through an 
opportunity through enhanced oil recovery.
    As we look at developing generation in today's time frame, 
we're looking at two technologies. IGCC, or integrated combined 
cycle, is one technology. The other one is what we call 
supercritical, or our pulverized coal type of technology. As 
has been said, capturing carbon off of a gas facility is much 
easier than trying to capture carbon off an existing PC 
facility.
    It's because of those things that we are engaged in 
activities at our Antelope Valley Station in conjunction with 
the Dakota Gasification project to understand how we might 
capture carbon off the back end of an existing pulverized coal 
facility. Our plan currently is to find a vendor that will have 
the right technology that matches up with what we're trying to 
get accomplished, capture CO2 off of the Unit I 
facility there at Antelope Valley and pipe it around to the 
existing infrastructure at Dakota Gasification. We then would 
look for customers for enhanced oil recovery in western North 
Dakota, eastern Montana, to avail ourselves of an opportunity 
to help offset the costs of that kind of technology.
    We believe that enhanced oil recovery is a bridge or a 
financial incentive to carbon capture. Again, the costs 
associated with this technology are extremely immense in our 
view, and so somehow there has to be a revenue stream to help 
offset those costs. We believe that there are opportunities out 
there to develop this technology. Our vendors' list is about 
nine at this point throughout this country. We've offered five 
on-site visits so far, so we believe there's a lot of interest 
in the same concepts that we're pursuing.

                           PREPARED STATEMENT

    One of the things that we think is also important, much 
like what you're trying to do within your committee, is to 
develop an opportunity to provide incentives for this research 
and development opportunities and ultimately to full-scale 
production that will again enhance our opportunity to continue 
to burn fossil fuels in this country.
    Mr. Chairman, that concludes my remarks and I would stand 
ready to address any questions that you or the other committee 
members might have. Thank you.
    [The statement follows:]
                 Prepared Statement of Ronald R. Harper
    Mr. Chairman and members of the committee, my name is Ron Harper 
and I serve as the CEO and General Manager of Basin Electric Power 
Cooperative. I appreciate the invitation to testify today, and I am 
here to provide you with Basin Electric's views on the future of coal 
as a fuel source for power generation, and Basin's efforts to address 
CO2 emissions from coal plants, while at the same time 
enhancing opportunities to increase domestic oil supply. The electric 
industry is going to build significant numbers of power plants, many of 
them coal-based, in the coming years to meet our Nation's growing 
electrical demand. The question of what to do with the carbon dioxide 
produced by these plants is casting a shadow over their viability. Coal 
is a vital part of our Nation's energy security, and the Federal 
Government should undertake an aggressive strategy to mitigate the risk 
of a carbon constrained future. For its part, Basin Electric is taking 
a leading role in finding these answers.
             a comprehensive solution to a complex problem
    Basin Electric is an electrical generation and transmission 
cooperative with 124 member cooperatives located in 9 States. Our 
generation resources include approximately 3,500 megawatts of coal, 
gas, oil and wind, but we are primarily a coal-based utility. As we 
look to the future, we know we must look at a broad range of solutions 
ranging from efficiency and conservation, to renewable energy, natural 
gas, and nuclear and how to utilize coal more efficiently.
    Basin Electric is committed to a diverse fuel mix in its generation 
portfolio. Today, Basin Electric has one of the largest wind energy 
resources in the region, with 137 megawatts of wind power. Our board 
recently approved plans to construct two 100-megawatt wind farms in 
North and South Dakota respectively which will be the first 
cooperatively-owned wind farms in the country. Basin Electric also 
utilizes four ``one-of-a-kind'' recycled energy systems, which use 
waste heat to produce 22 megawatts of power without any additional fuel 
consumption or emissions. Four more of these systems are scheduled to 
be built in the near future.
    In November 2005, our membership adopted a goal that by 2010, Basin 
Electric would have renewable resources in its generation portfolio in 
an amount equal to 10 percent of the capacity needed to meet the 
demands of our members. With our existing and planned wind and recycled 
energy projects, we are well on our way to achieving that goal. 
However, Basin Electric needs significant base-load generation and, for 
the foreseeable future, that will come from coal.
                 coal--a necessary part of the solution
    Basin Electric is growing and we are looking at developing new 
base-load generation. After reviewing all of our options, it became 
clear to us that to meet our needs for low cost base-load power, the 
best choice was coal. Both North Dakota and Wyoming have ample supplies 
of coal and we have considerable knowledge of building and operating 
coal-based generation plants. We have built gas generation for peaking 
purposes and will build more. However, we do not believe it is prudent 
to build base-load gas generation and expose our membership to 
significant fluctuations in natural gas prices. To provide base-load 
power, Basin Electric is developing two coal-based facilities, one is 
the Dry Fork Station in Wyoming and the other will be located either in 
North Dakota or South Dakota.
    Coal provides 50 percent of the electricity generated in the United 
States. It is our most abundant domestic resource and will continue to 
play an important role in meeting our Nation's energy needs. However, 
new technology must be developed to use this resource more wisely and 
efficiently, including addressing how to capture the CO2 
emissions. The Energy Policy Act of 2005 was a step in the right 
direction in providing tax incentives, loan guarantees, and other 
programs to encourage the commercial development of the next generation 
of clean coal technology.
       an example for the future--the great plains synfuels plant
    The questions surrounding carbon dioxide emissions from coal-based 
facilities complicate future development. These CO2 
questions must be answered to ensure coal's continued place as a 
reliable, low-cost fuel source. I believe that part of the answer to 
these questions exist at Basin Electric. Basin Electric is taking a 
leading role in several carbon initiatives, including its membership in 
the Plains CO2 Reduction (PCOR) partnership and work with 
the Canadian Clean Power Coalition.
    However, the best and largest example of low-carbon coal is through 
Basin Electric's subsidiary Dakota Gasification Company, which owns the 
Great Plains Synfuels Plant in Beulah, North Dakota. In 2000, DGC began 
delivering carbon dioxide to oil producers in Saskatchewan, Canada. We 
currently capture roughly 49 percent of the CO2 produced at 
the plant, and ship it to Canada through a 205-mile pipeline to 
Weyburn, Saskatchewan to be used for enhanced oil recovery (EOR) in an 
aging oil field. Today, DGC provides all the CO2 to the 
largest carbon sequestration project in the world. Through 2006, Dakota 
Gasification has successfully captured and marketed over 10 million 
tons of carbon dioxide to two Canadian customers. Total carbon dioxide 
demand is 152.7 million standard cubic feet per day. The carbon dioxide 
is expected to be permanently sequestered in the oil reservoir and is 
being monitored by the International Energy Agency (IEA) Weyburn 
CO2 Monitoring and Storage Project.
                       two paths forward for coal
    We have learned a great deal about what works and what doesn't work 
with carbon capture and sequestration over the last 7 years. The 
Synfuels Plant, however, is unique. The plant produces synthetic 
natural gas that is pipeline quality. Given the major differences 
between producing pipeline quality gas and producing gas to generate 
electricity, it is not a simple task to translate this technology to 
power production. When building new coal-based generation, a utility 
has somewhat limited technology choices. The two most prominent 
include: Integrated Gasification Combined Cycle (IGCC) or supercritical 
(ultra-supercritical) Pulverized Coal (PC).
IGCC Option
    Integrated Gasification Combined Cycle (IGCC) uses the same basic 
concept in operation at the Synfuels Plant. However, an IGCC power 
plant would not need to purify the gas to a high degree for the gas to 
be used in a combustion turbine to produce electricity. The cost of a 
new 600 megawatt (MW) IGCC power plant is anywhere from 10 to 20 
percent higher than a comparable Supercritical PC plant. Adding carbon 
capture equipment on the back end considerably increases those costs, 
and the expense of efficiency.
    We are confident that the carbon capture would work on an IGCC 
facility. However, we are not sure that low rank coals, such as lignite 
and sub-bituminous, will work effectively in an IGCC facility. Basin 
Electric and the Lignite Energy Council have sent North Dakota Lignite 
to the Department of Energy's IGCC testing facility in Alabama in the 
past, but the testing raised questions with respect to the sodium 
content of lignite. This has delayed any long-term testing that could 
readily answer questions about how IGCC works on low rank coals. The 
same is true for sub-bituminous coal, as most of the testing and 
commercial application of the technology remains focused on low-
moisture, eastern bituminous coal.
    In 2006 Basin Electric partnered with General Electric and Bechtel 
Corporation to submit an application to the Department of Energy for 
tax credits to construct a new power plant in South Dakota which would 
use Integrated Gasification Combined Cycle (IGCC) technology. 
Unfortunately, due to problems with the authorizing statute, no 
projects using sub-bituminous coal, such as this one, were considered. 
That legislation has since been fixed, and Basin Electric and GE are 
reviewing our options to submit a second application for the 2007 
round.
PC Option
    While IGCC has its own questions regarding low-rank coals, Basin 
Electric is confident that a supercritical PC plant will work with low-
rank coals to generate power. On the other hand, carbon capture 
technology has not been developed for PC plants. Much of the technology 
is in early development and needs further research. There are hundreds 
of pulverized coal plants still operating around the country that have 
decades of useful life left. These plants cannot be shut down or 
converted overnight, so a way must be found to capture and sequester 
the CO2 from these facilities as well. Supercritical PC 
plants can be just as efficient as an IGCC plant, so they should be 
considered for similar incentives to help capture and sequester carbon 
dioxide.
    In order to facilitate the development of this technology, Basin 
Electric recently issued a Request For Proposal to demonstrate carbon 
dioxide capture at one of our existing plants, the Antelope Valley 
Station. CO2 would be captured from the flue gases at 
Antelope Valley, piped to the neighboring Great Plains Synfuels plant, 
and added to the existing CO2 pipeline system. This would 
add nearly 60 million standard cubic feet of gas to the pipeline for 
enhanced oil recovery in North Dakota's Williston Basin or at other 
regional sites. We currently estimate the cost of demonstrating carbon 
dioxide capture on a small portion of the 900 MW plant, around 100 MWs, 
would be roughly $100 to $150 million. We have received several 
responses, and have met with interested vendors on site, and are in the 
process of evaluating their proposals.
        technology horserace--a balanced approach to incentives
    Federal incentives need to be technology neutral. Supercritical PC 
and IGCC both have a place in our Nation's electricity portfolio. At 
this point and time there is no clear indication that one of these 
technologies will become the choice for capturing and sequestering 
carbon. The Investment Tax Credit (ITC) authorized in the Energy Policy 
Act of 2005 is essential for building the first plant to demonstrate a 
``carbon capture ready'' IGCC plant using low rank coals. In addition, 
the Senate Finance Committee recently proposed a $10 per ton production 
tax credit for carbon capture and coal facilities. Both of these 
incentives need be to available in the future if viable technology 
solutions are to be fully explored.
             enhanced oil recovery--a bridge for technology
    Enhanced oil recovery can provide a financial incentive to carbon 
capture. The current effort to sequester carbon from coal based 
facilities requires intensive capital. Enhanced oil recovery can 
provide one mechanism to reduce that cost. However, even the potential 
for revenue from selling CO2 does not fully support the 
business case of adding carbon capture to a plant. A combination of 
construction and production incentives is necessary to such a system 
financially and commercially viable. A $10 per ton production tax 
credit for carbon sequestration would provide this support, and benefit 
both IGCC and pulverized coal, without discriminating against the 
generation process used. Add to that a $250 million investment tax 
credit, and you would go a long way to enhance the prospect of building 
IGCC and PC plants that capture carbon dioxide.
    Mr. Chairman, in conclusion, the Energy Policy Act provides 
important tools in helping build the next generation of coal-based 
power plants. These tools need to be expanded to provide electric 
utilities with the assistance they need to develop the next generation 
of power plants and efficiently capture and sequester carbon dioxide 
from existing and future power plants. Thank you again for holding this 
important hearing. I am available to answer any questions.

    Senator Dorgan. Thank you very much. Next we'll hear from 
John Weeda from Great River Energy Company. Thank you for being 
here.
STATEMENT OF JOHN WEEDA, PLANT MANAGER, COAL CREEK 
            STATION, GREAT RIVER ENERGY
    Mr. Weeda. Thank you, Senator Dorgan, and thank you for the 
privilege of testifying here today.
    Great River Energy owns and operates generation facilities 
in North Dakota, and we want to expand those facilities in the 
State, and those plans include innovative uses of coal to allow 
us to meet growing energy needs and help reduce the country's 
dependence on foreign oil, and do it all in an environmentally 
sensitive manner.
    Our existing plants are reliable and they are regularly 
updated to incorporate updates in emission controls and enhance 
the operations.
    Great River Energy plans to build a third power plant in 
North Dakota, the Spiritwood Station. It's a 99-megawatt 
combined heat and power facility located about 8 miles east of 
Jamestown, North Dakota. As a combined heat and powerplant, 
Spiritwood will generate electricity for the electric grid and 
steam to power the neighboring malt plant and a proposed 100-
million-gallon-per-year ethanol plant. Doing so will be a 
highly efficient operation, about 66 percent compared to most 
coal-based plants are 30 to 35 percent efficient. It's because 
of taking advantage of the energy which would normally be 
released to the cooling towers.
    Fuel for the coal-based combined heat and power plant will 
be beneficiated lignite, supplied by Great American Energy. 
Highly efficient technologies such as combined heat and power 
offer additional opportunities for the reduction of regulated 
emissions and carbon dioxide, as well.
    Great River Energy is also commercializing an innovative 
coal-drying technology that was developed at Coal Creek 
Station. This process uses waste heat from the powerplant to 
improve the quality of the lignite, and, as a result, Coal 
Creek Station will use approximately 10 percent less coal and 
the plant's efficiency will increase approximately 5 percent. 
In addition, emissions are expected to be reduced, as well as 
plant maintenance. The efficiency improvements also result in 
less CO2 per megawatt of electricity generated. The 
coal dryer also removes mercury. And Great River Energy is 
proud to comment that we partnered with the U.S. Department of 
Energy's Clean Coal Power Initiative on this project.
    We also use additional steam from Coal Creek Station to 
power the Blue Flint Ethanol Plant. And because a majority of 
the ethanol energy required is waste heat from the adjacent 
Coal Creek Station, Blue Flint Ethanol did not have to build a 
$25 million boiler, thus making it a low-cost source of 
ethanol. Because the plant is collocated with Coal Creek 
Station, it has fewer emissions and uses less water compared to 
an ethanol plant at a Greenfield site.
    Great River Energy, Headwaters Energy Services and North 
American Coal Corporation are exploring the development of a 
North Dakota-based coal refinery to produce ultra clean 
transportation fuels and electricity. This polygeneration plant 
would use about 10 million tons of North Dakota lignite 
annually. The integrated process would result in about 32,000 
barrels of transportation fuel and 150 to 250 megawatts of 
electricity and other by-products.
    The project would utilize proven technology to capture 
carbon dioxide emissions from the plant, which would then be 
utilized for enhanced oil recovery in western North Dakota. It 
incorporates carbon capture into its design and is expected to 
remove and sequester 70 percent of the total CO2 
produced in the process. CO2 would be sold to 
oilfield operators to use in EOR, which is commercially 
demonstrated technology for use of CO2.
    As a result, the carbon footprint for American Lignite 
Energy fuels will be equal to or less than the domestic fuels 
that they replace and better than fuels derived from imported 
petroleum. Electricity from the project's generating facility 
will have CO2 intensity equal to or better than a 
natural gas-fired combined cycle plant.
    However, if the United States desires a coal-to-liquid 
industry and more energy independence, the development of the 
industry will require Federal incentives to help address the 
financial market risk associated with oil price volatility and 
commercializing the industry.

                           PREPARED STATEMENT

    All of this activity helps spur the North Dakota economy. 
Great River Energy is playing a significant role in economic 
development efforts in North Dakota. Great River Energy is a 
responsible environmental company and progressive, and we've 
established a goal to reduce greenhouse gas emissions to below 
2000 levels by 2020. To accomplish our goals, we are focused on 
a number of solutions that support a sustainable environment, 
including energy conservation, renewable energy sources, carbon 
capture, storage/sequestration research, and other initiatives.
    Thank you, Mr. Chairman, and I would be pleased to answer 
your questions.
    [The statement follows:]
                    Prepared Statement of John Weeda
    Mr. Chairman and members of the subcommittee, my name is John 
Weeda. I am Great River Energy's plant manager at Coal Creek Station 
near Underwood, North Dakota. Thank you for the opportunity to testify 
today.
    Great River Energy is a generation and transmission cooperative 
based in Elk River, Minnesota. that provides wholesale electric power 
to 28 distribution cooperatives. We own power generation facilities in 
North Dakota and plan to expand our operations in the State. Those 
plans include innovative uses of coal that will allow us to meet 
growing energy demands and help reduce the country's dependence on 
foreign oil--all done in an environmentally sensitive manner.
    Great River Energy's existing coal power plants--Coal Creek Station 
and Stanton Station--are reliable and efficient baseload generating 
stations. We regularly update their emissions controls and enhance 
their operations. Great River Energy values its reputation as an 
environmental leader among utilities. We have made a strategic 
commitment to environmental stewardship and are acting on the evidence 
that climate change is real by pursuing initiatives that support a 
sustainable environment. Our commitment is based on our core operating 
principle to make the right environmental choices within our 
technological and financial capabilities.
    Great River Energy plans to build a third power plant in North 
Dakota--Spiritwood Station--a 99-megawatt combined heat and power 
facility, located about 8 miles east of Jamestown, North Dakota, near 
Spiritwood. As a combined heat and power plant, Spiritwood Station will 
generate electricity for the electric grid and steam to power a 
neighboring malting plant and a proposed 100-million-gallon per year 
ethanol plant. Doing so results in a highly energy efficient power 
plant--at about 66 percent, as compared to most coal-based power plants 
which are about 30 to 35 percent efficient. This is because the plant 
will take advantage of the energy in the steam which is normally 
released to cooling towers.
    Fuel for the coal-based, combined heat and power plant will be 
beneficiated lignite, supplied by Great American Energy. The lignite 
product will be 7,500 Btus per pound with 25 percent moisture (upgraded 
from 6,200 Btus per pound with 38 percent moisture). The power plant 
would also use Best Available Control Technologies to meet and exceed 
the stringent health based air quality standards.
    Construction of Spiritwood Station would begin following approval 
of the plant's air emissions permit by the North Dakota Department of 
Health. If granted this September, the plant would then be scheduled to 
start operating in the first quarter of 2010--following 2.5 years of 
construction.
    Highly efficient technologies such as combined heat and power offer 
additional opportunities for the reduction of regulated emissions and 
carbon dioxide (CO2). Great River Energy supports the 
development of Federal and State-level incentives for the development 
of these facilities that provide electricity while producing steam that 
can be used to power other industrial operations.
    Great River Energy is commercializing an innovative coal drying 
system that was developed at Coal Creek Station. The process uses waste 
heat from the power plant to improve the quality of lignite. As a 
result Coal Creek Station will use approximately 10 percent less coal, 
and the plant's efficiency will increase approximately 5 percent. In 
addition, emissions are expected to be reduced, as well as plant 
maintenance. The efficiency improvement also results in less 
CO2 per megawatt of electricity generated. The coal dryer 
also removes mercury. Eight dryers will be built at Coal Creek Station, 
four for each of the plant's two units, with full operation of the 
system expected by mid-2009. Great River Energy partnered with the U.S. 
Department of Energy's Clean Coal Power Initiative on the project. 
Great River Energy will work with partners such as Headwaters and North 
American Coal to market this technology to other power plants that 
utilize lignite or subbituminous coal. Great River Energy and North 
American Coal Corporation have formed a new organization called Great 
American Energy to sell additional beneficiated lignite to other coal 
consumers in North Dakota.
    We use additional steam from Coal Creek Station to power the Blue 
Flint Ethanol plant. Great River Energy is a minority owner and service 
provider for the ethanol plant, a 50-million-gallon per year plant near 
Underwood. Headwaters Incorporated is the majority owner and operator. 
Because a majority of the energy for the ethanol plant is waste steam 
from the adjacent Coal Creek Station, Blue Flint Ethanol did not have 
to build a $25 million boiler, making it a low-cost source of ethanol. 
Also, because the plant is co-located with Coal Creek Station, it has 
fewer emissions and uses less water as compared with an ethanol plant 
at a Greenfield site. The plant also produces enough distillers grain 
for about 225,000 head of feeder cattle annually. Carbon dioxide from 
ethanol plants is a potential for sequestration. Headwaters and Great 
River Energy are investigating options for a demonstration project.
    Our activities are not limited to generating electricity or 
enhancing ethanol production.
    Great River Energy, Headwaters Energy Services and The North 
American Coal Corporation are exploring the development of a North 
Dakota coal-based refinery to produce ultra clean liquid transportation 
fuels and electricity. This polygeneration plant would use about 10 
million tons of North Dakota lignite annually. The integrated process 
would result in about 32,000 barrels of transportation fuels and 150 to 
250 MW of electricity and other byproducts.
    The partners have completed several preliminary engineering, 
environmental and market studies, and have started more detailed 
engineering activities to further their analysis. Final site 
identification is under way. If the project were to move forward, 
engineering and permitting of the facility could take at least 2 years. 
Financing and construction of the facility would take at least 4 
additional years. Engineering activities are being supported in part by 
North Dakota's Lignite Research Fund, with the North Dakota Industrial 
Commission committing $10 million towards the project.
    The project would utilize proven technology to capture carbon 
dioxide emissions from the plant, which then could be utilized for 
enhanced oil recovery in western North Dakota. It incorporates carbon 
capture (CO2) into its design that is expected to remove and 
sequester 70 percent of the total CO2 produced in the 
process. The CO2 will be sold to North Dakota oil field 
operators for use in enhanced oil recovery, which is a commercially 
demonstrated technology for sequestering CO2. Enhanced oil 
recovery has been practiced for decades in Texas and in the Canadian 
Weyburn fields since 2000. The Williston Basin's demand for 
CO2 is projected to be greater than American Lignite 
Energy's CO2 production.
    As a result, the carbon footprint for American Lignite Energy fuels 
will be equal to the domestic fuels they replace and better than fuels 
derived from imported petroleum. Electricity from the project's 
generating facility will have a CO2 intensity equal to or 
better than that of a natural-gas-fired combined cycle plant.
    However, if the United States desires a coal-to-liquids industry--
and more energy independence--the development of the industry will 
require Federal incentives to help address financial market risk 
associated with oil price volatility and commercializing the industry.
    All of this activity helps spur the North Dakota economy. Great 
River Energy is playing a significant role in economic development 
efforts in North Dakota. Blue Flint Ethanol is a $95 million plant that 
employs 37 people. The plant purchases corn from North Dakota farmers, 
and also sells ethanol and distillers grain for about 225,000 feeder 
cattle per year. Spiritwood Station will cost approximately $275 
million and employ about 42 people when operational, and will utilize 
upgraded lignite from Great American Energy. Great American Energy is a 
$20 million venture that will have the capacity to supply one to three 
million tons of upgraded lignite. American Lignite Energy, if built, 
could be the largest project ever in North Dakota.
    Great River Energy is an environmentally progressive energy 
company. We have established a goal to reduce its greenhouse gas 
emissions to below 2000 levels by 2020. This is an expected 20 percent 
reduction from historical emissions despite the fact that we are one of 
the fastest growing electric utilities in the region. In addition, 25 
percent of Great River Energy's energy will come from renewable 
resources by 2025. To accomplish our goals, we are focused on a number 
of solutions that support a sustainable environment, including energy 
conservation, renewable energy sources, carbon capture and storage/
sequestration research, and other initiatives.
    Mr. Chairman, I would be pleased to answer any questions you may 
have.
    Thank you.

    Senator Dorgan. Mr. Weeda, thank you very much. Next we'll 
hear from Rod Nelson, who comes to us from Texas. He is vice 
president of Schlumberger Limited, and he is speaking on behalf 
of the National Petroleum Council. Mr. Nelson, you may proceed.
STATEMENT OF ROD NELSON, VICE PRESIDENT, SCHLUMBERGER 
            LIMITED ON BEHALF OF THE NATIONAL PETROLEUM 
            COUNCIL
    Mr. Nelson. Thank you, Mr. Chairman. I appreciate this 
opportunity, first off, speaking about this important subject 
of carbon management. And I am representing the National 
Petroleum Council here today and the oil and gas industry, if 
you want to ask some questions later.
    The National Petroleum Council recently completed a study 
and presented to Secretary Bodman, a study of the energy future 
entitled Facing the Hard Truths about Energy.
    Senator Dorgan. Can you pull that microphone just a little 
closer?
    Mr. Nelson. Is that better?
    Senator Dorgan. Better, yes.
    Mr. Nelson. Let me give you a very brief summary of the 
findings of that study then I'll go quickly to the carbon 
capture and sequestration question.
    The National Petroleum Council examined a broad range of 
global energy supply, demand, and technology projections 
through 2030. The Council identified risks and challenges to a 
reliable energy future and developed strategies and 
recommendations aimed at balancing future economic, security, 
and environmental goals. The Council proposed five core 
strategies which must be addressed together.
    First, moderating the growing demand for energy by 
increasing efficiency.
    Next, expand and diversify production from all economic, 
environmentally acceptable energy sources, as you've already 
heard.
    Integrate energy policy into trade, economic, 
environmental, security, and foreign policies.
    Enhance science and engineering capabilities and create 
opportunities for research and development.
    And, finally, because we are likely moving into an era in 
which carbon emissions will be constrained, develop the legal 
and regulatory framework to enable carbon capture and 
sequestration (CCS). In addition, as policymakers consider 
options to reduce CO2 emissions, provide an 
effective global framework for carbon management, including 
establishment of a transparent, predictable, economy-wide cost 
for CO2 emissions.
    So with that background, let me now speak more directly to 
carbon capture and sequestration, which we think can facilitate 
the continued use of fossil fuels that we have already 
discussed. Carbon capture and sequestration, or CCS, entails 
trapping CO2 at the site where it's generated and 
storing it for a period sufficiently long--several thousand 
years, one would guess--in geologic targets, probably spent oil 
and gas reservoirs or deep saline formations.
    The technologies required for effective CCS are, by and 
large, viable today. Projects include Sleipner, Weyburn, which 
you heard about, In Salah saline formation project in Algeria. 
The hurdles to implementation are largely ones of integration 
and scale. To put things in perspective, sequestering 
CO2 emissions from a one-gigawatt coal-fired power 
station requires pumping into the ground about 150,000 barrels 
per day of supercritical or liquid CO2.
    While the technologies for CCS are essentially available 
and viable, in that capture and storage can be implemented now, 
extensive scope remains for improvement. In particular, the 
capture stage of CCS is the key, and you've already heard that 
from Carl and that dominates the overall cost.
    It's important to note that there is no experience 
available with a full-scale integration process today, in other 
words, a coupled, large-scale coal-fired powerplant with CCS. 
Several projects worldwide, most notably FutureGen in the 
United States and Zero-Gen in Australia, are in the process of 
designing such an experiment. Operating such facilities 
successfully is central to understanding the true economics and 
practical requirements for large-scale CCS.
    One activity in which CO2 is pumped into 
reservoirs currently is enhanced oil recovery (EOR). This 
provides a proving ground for various techniques that are 
relevant to CCS, and can be implemented while other carbon 
management solutions are under development. At present, most 
CO2 EOR is not directed toward effective storage of 
CO2, but the techniques can be modified to improve 
carbon sequestration for longer term.

                           PREPARED STATEMENT

    So let me try to summarize. The challenges facing our 
energy future are daunting, but not insurmountable. Given the 
massive scale of the global energy system and the long lead 
times necessary to make significant changes, concerted actions 
are needed now to promote U.S. competitiveness by balancing 
economic, security, and environmental goals. Carbon dioxide 
emissions are by their very nature a global issue, and 
atmospheric concentrations respect no geographic boundary. As 
such, ultimately a global solution is required. Carbon capture 
and storage is in some ways a unique opportunity for the United 
States to develop technology and demonstrate leadership. We 
have large remaining fossil fuel reserves which could be 
economically and environmentally converted using carbon capture 
technology. We have the infrastructure and the sedimentary 
basins to sequester the CO2. The regulatory and 
legislative framework within which CCS is conducted will have a 
major impact on how rapidly the technology is implemented. The 
oil and gas industry has the skill sets to further develop and 
deploy this technology, but, clearly, cross-industry and 
government cooperation is required. Thank you.
    [The statement follows:]
                    Prepared Statement of Rod Nelson
    Thank you, Senator for the opportunity to testify regarding the 
important subject of carbon management. I am here representing the 
National Petroleum Council, which has recently completed and presented 
to Secretary of Energy Bodman, a comprehensive study of the energy 
future entitled ``Facing the Hard Truths about Energy,'' and the oil 
and gas industry. I would like to start by giving you a very short 
summary of the findings from this landmark study and then delve more 
deeply into the carbon capture and sequestration opportunity.
                   npc report findings and background
    The American people are very concerned about energy--its 
availability, reliability, cost, and environmental impact. Energy also 
has become a subject of urgent policy discussions. But energy is a 
complex subject, touching every part of daily life and the overall 
economy, involving a wide variety of technologies, and deeply affecting 
many aspects of our foreign relations. The United States is the largest 
participant in the global energy system--the largest consumer, the 
second largest producer of coal and natural gas, and the largest 
importer and third largest producer of oil. Developing a framework for 
considering America's oil and natural gas position now and for the 
future requires a broad view and a long-term perspective.
    During the last quarter-century, world energy demand has increased 
about 60 percent, supported by a global infrastructure that has 
expanded to a massive scale. Most forecasts for the next quarter-
century project a similar percentage increase in energy demand from a 
much larger base. Oil and natural gas have played a significant role in 
supporting economic activity in the past, and will likely continue to 
do so in combination with other energy types. Over the coming decades, 
the world will need better energy efficiency and all economic, 
environmentally responsible energy sources available to support and 
sustain future growth.
    Fortunately, the world is not running out of energy resources. But 
many complex challenges could keep these diverse energy resources from 
becoming the sufficient, reliable, and economic energy supplies upon 
which people depend. These challenges are compounded by emerging 
uncertainties: geopolitical influences on energy development, trade, 
and security; and increasing constraints on carbon dioxide 
(CO2) emissions that could impose changes in future energy 
use. While risks have always typified the energy business, they are now 
accumulating and converging in new ways.
    The National Petroleum Council examined a broad range of global 
energy supply, demand, and technology projections through 2030. The 
Council identified risks and challenges to a reliable and secure energy 
future, and developed strategies and recommendations aimed at balancing 
future economic, security, and environmental goals.
    The United States and the world face hard truths about the global 
energy future over the next 25 years:
  --Coal, oil, and natural gas will remain indispensable to meeting 
        total projected energy demand growth.
  --The world is not running out of energy resources, but there are 
        accumulating risks to continuing expansion of oil and natural 
        gas production from the conventional sources relied upon 
        historically. These risks create significant challenges to 
        meeting projected energy demand.
  --To mitigate these risks, expansion of all economic energy sources 
        will be required, including coal, nuclear, renewables, and 
        unconventional oil and natural gas. Each of these sources faces 
        significant challenges--including safety, environmental, 
        political, or economic hurdles--and imposes infrastructure 
        requirements for development and delivery.
  --``Energy Independence'' should not be confused with strengthening 
        energy security. The concept of energy independence is not 
        realistic in the foreseeable future, whereas U.S. energy 
        security can be enhanced by moderating demand, expanding and 
        diversifying domestic energy supplies, and strengthening global 
        energy trade and investment. There can be no U.S. energy 
        security without global energy security.
  --A majority of the U.S. energy sector workforce, including skilled 
        scientists and engineers, is eligible to retire within the next 
        decade. The workforce must be replenished and trained.
  --Policies aimed at curbing CO2 emissions will alter the 
        energy mix, increase energy-related costs, and require 
        reductions in demand growth.
    Free and open markets should be relied upon wherever possible to 
produce efficient solutions. Where markets need to be bolstered, 
policies should be implemented with care and consideration of possible 
unintended consequences. The Council proposes five core strategies to 
assist markets in meeting the energy challenges to 2030 and beyond. All 
five strategies are essential--there is no single, easy solution to the 
multiple challenges we face. However, the Council is confident that the 
prompt adoption of these strategies, along with a sustained commitment 
to implementation, will promote U.S. competitiveness by balancing 
economic, security, and environmental goals. The United States must:
  --Moderate the growing demand for energy by increasing efficiency of 
        transportation, residential, commercial, and industrial uses.
  --Expand and diversify production from clean coal, nuclear, biomass, 
        other renewables, and unconventional oil and natural gas; 
        moderate the decline of conventional domestic oil and gas 
        production; and increase access for development of new 
        resources.
  --Integrate energy policy into trade, economic, environmental, 
        security, and foreign policies; strengthen global energy trade 
        and investment; and broaden dialogue with both producing and 
        consuming nations to improve global energy security.
  --Enhance science and engineering capabilities and create long-term 
        opportunities for research and development in all phases of the 
        energy supply and demand system.
  --Develop the legal and regulatory framework to enable carbon capture 
        and sequestration (CCS). In addition, as policymakers consider 
        options to reduce CO2 emissions, provide an 
        effective global framework for carbon management, including 
        establishment of a transparent, predictable, economy-wide cost 
        for CO2 emissions.
    All five strategies must be addressed together, global cooperation 
is required, and we must begin now and plan sustained commitment.
    With that background, let me know turn to carbon capture and 
sequestration (CCS) underground which can facilitate the continued use 
of fossil fuels in an increasingly carbon-constrained world. CCS is 
technically achievable today, and has been demonstrated at a project 
level and applied in enhanced oil recovery. However, carbon dioxide has 
not been injected at the scales (both volumes and time periods) that 
will be necessary in the future.
                    carbon capture and sequestration
    It is likely that the world is moving into an era in which carbon 
emissions will be constrained. Oil and natural gas contribute more than 
half the current, energy-related CO2 emissions. In a carbon-
constrained world, the use of oil, natural gas and coal will be 
affected by policy measures to reduce carbon emissions. Carbon 
management will involve combining several measures to reduce 
CO2 emissions, including improvements in the efficiency of 
energy use and the use of alternatives to fossil fuels such as 
biofuels, solar, wind, and nuclear power. However, to meet the energy 
demands of the Nation, the United States will continue using fossil 
fuels, including coal, extensively over the next 50 years or more. To 
do so, and to extend the resource base to include unconventional 
hydrocarbons such as heavy oil, tar sands, and shale oil, it will be 
necessary, if carbon constraints are imposed, to capture and sequester 
a large fraction of the CO2 produced by burning these fossil 
fuels.
    Carbon capture and sequestration (CCS) entails trapping 
CO2 at the site where it is generated and storing it for 
periods sufficiently long (several thousand years) to mitigate the 
effect CO2 can have on the Earth's climate. I will only 
consider geological sequestration and won't discuss possible 
alternatives, such as deep-sea sequestration, which is fraught with 
environmental concerns and issues of public acceptance. Geological 
sequestration would target spent oil and natural gas reservoirs and 
deep saline formations.
    The technologies required for effective CCS are, by and large, 
viable. Projects continue at Sleipner field, the Weyburn EOR project in 
Canada,\1\ and the In Salah saline formation project in Algeria.\2\ The 
hurdles to implementation are largely ones of integration at scale. 
Current possible scenarios of climate change predict that by 2056, the 
level of carbon to be mitigated could be 7 billion tons per year or 
more.\3\ \4\ Sequestering a billion tons of carbon each year would 
entail pumping about 80 million barrels per day of supercritical 
CO2 into secure geological formations. This amounts to about 
a quarter of the volume of water currently pumped worldwide for 
secondary oil recovery. At the local level, sequestering CO2 
from a 1-gigawatt coal-fired power station would require pumping into 
the ground some 150,000 barrels per day of supercritical 
CO2.\5\ A power station of that size would generate 
electricity for about 700,000 typical American homes.
---------------------------------------------------------------------------
    \1\ Wilson M, Monea M. (Eds.), IEA GHG Weyburn CO2 
Monitoring & Storage Project Summary Report 2000-2004 (2004), 273 p.
    \2\ Riddiford, F, Wright, I, Espie, T, and Torqui, A: ``Monitoring 
geological storage: In Salah Gas CO2 Storage Project,'' 
GHGT-7, Vancouver (2004).
    \3\ Pacala and Socolow: ``Stabilization Wedges: Solving the Climate 
Problem for the next 50 Years with Current Technology,'' Science 305 
(13 Aug. 2004): 968.
    \4\ Third Assessment Report--Climate Change 2001, Intergovernmental 
Panel on Climate Change.
    \5\ Socolow R: ``Can We Bury Global Warming,'' Scientific American 
(2005).
---------------------------------------------------------------------------
    While the technologies for CCS are essentially available, in that 
capture and storage can be implemented now, extensive scope remains for 
improvement. In particular, the capture stage of CCS is key, and 
currently dominates the overall cost. Novel, lower-cost approaches to 
capture would have a significant effect on the implementation of CCS 
and would, in turn, greatly influence the usability of fossil fuels 
under carbon constraint. Other areas where continued research is 
important:
  --Fundamentals of storage, such as long-term physiochemical changes 
        in the storage reservoir;
  --Characterization and risk assessment (faults, cap rocks, wells);
  --Reservoir management for long term storage;
  --Integration of fit-for-purpose measurement, monitoring and 
        verification;
  --Ability to inject CO2 into formations; and
  --Retention and leakage, such as leakage through wells.
    It is also crucial at this stage to undertake an assessment of the 
total U.S. capacity for CO2 sequestration. While it is 
reasonable to expect that the combined capacity of existing hydrocarbon 
reservoirs and deep saline formations is large, a detailed 
understanding of the regional distribution of capacity throughout the 
United States is critically important.
    It is important to note that there is no experience available with 
full-process integration, e.g. a coupled, large-scale coal-fired power 
plant with CCS. Several projects world-wide, most notably FutureGen in 
the United States and Zero-Gen in Australia, are in the process of 
designing and constructing an integrated large-scale power and CCS 
operation. Operating such facilities successfully is central to 
understanding the true economics and practical requirements for large-
scale CCS.
    One activity in which CO2 is pumped into reservoirs 
currently is enhanced oil recovery (EOR). This provides a proving 
ground for various techniques that are relevant to CCS, and can be 
implemented while other carbon-management solutions are under 
development. At present, CO2-EOR is not directed towards 
effective storage of CO2 but the techniques can be modified 
to improve carbon sequestration.
    A recent study completed by Kuuskraa \6\ for the DOE suggests that 
application of advanced EOR techniques can increase U.S. recoverable 
oil resources. A total of 10 domestic oil basins and areas have now 
been assessed. These assessments indicate that the technically 
recoverable oil resource from application of ``state-of-the-art'' 
CO2-EOR is 89 billion barrels. In addition, new work on the 
transition/residual oil zone resource documents the presence of 42 
billion barrels of this category of oil in place in just 3 domestic oil 
basins (Permian, Big Horn, and Williston). Detailed reservoir 
simulation assessment shows that about 20 billion barrels of this oil 
in place could become technically recoverable by applying 
CO2-EOR. Finally, an in-depth look at the additional oil 
recovery from applying ``next generation'' CO2-EOR 
technology found further potential. This work shows that combining: (1) 
advanced, high reservoir contact well designs; (2) mobility and 
miscibility enhancement; (3) large volumes of CO2 injection; 
and (4) real-time performance feedback and process control technology 
could bring about ``game changer'' levels of improvement in oil 
recovery efficiency.
---------------------------------------------------------------------------
    \6\ Kuuskraa VA: ``Undeveloped Domestic Oil Resources: The 
foundation for Increasing Oil Production and a Viable Domestic Oil 
Industry''
---------------------------------------------------------------------------
    Government incentives for CO2 storage in association 
with CO2-EOR, and new arrangements for developing suitable 
infrastructure for commercial use of anthropogenic CO2 for 
EOR with storage, could help CO2-EOR for storage succeed, 
particularly as CO2 becomes increasingly available (and 
increasingly cheap) under a wide-scale adoption of CCS.
    There is now a scientific consensus that anthropogenic 
CO2 is driving detrimental climate change.\7\ Moreover, the 
Intergovernmental Panel on Climate Change (IPCC) Special Report on CCS 
indicates that including it in a mitigation portfolio could help 
stabilize CO2 concentrations in the atmosphere (at double 
the pre-industrial level) with a cost reduction of 30 percent or more, 
compared to other approaches.\8\ More recently, the UK's Stern Review 
estimated that the cost of meaningful mitigation--maintaining 
atmospheric levels of CO2 at no more than double the pre-
industrial levels--would amount to about 1 percent of global GDP.\9\ 
Doing nothing, on the other hand, would likely incur a greater cost. 
These studies indicate that the financial risk to the Nation of 
delaying action is now so high that a concerted emphasis on CCS is 
already strongly warranted.
---------------------------------------------------------------------------
    \7\ Oreskes, N: ``The Scientific Consensus on Climate Change,'' 
Science 306 (3 Dec. 2004): 1686.
    \8\ ``IPCC Special Report on Carbon Dioxide Capture and Storage,'' 
Intergovernmental Panel on Climate Change, Interlachen (2005), 
available at http://www.ipcc.ch/.
    \9\ ``The Stern Review of the Economics of Climate Change,'' 
available at http://www.hmtreasury.gov.uk/independent_reviews/
stern_review_economics_climate_change/stern_review_report.cfm.
---------------------------------------------------------------------------
Summary--Technical Issues
    Tables T-V.1, T-V.2, and T-V.3 describe the basis for experience 
relevant to commercial CCS, current technologies in priority order, and 
future technologies in time/priority order, with time scales to 
commercial use.
    Technology today is well-understood and effective and can probably 
deliver what is needed. However, there are some outstanding technical 
issues:
  --Novel, lower cost capture technologies;
  --Integration and fit-for-purpose deployment of monitoring and 
        verification;
  --Well leakage characterization and mitigation;
  --Protocols for site characterization; and
  --Technical basis for operational protocols and risk 
        characterization.

      TABLE T-V.1.--BASIS FOR EXPERIENCE RELEVANT TO COMMERCIAL CCS
------------------------------------------------------------------------
        Experience Basis             Significance         Limitations
------------------------------------------------------------------------
CO2 enhanced oil recovery (EOR).  > 30 years          Very limited
                                   experience;         monitoring
                                   injection  >>1 M    programs;
                                   tons CO2/year.      questions of
                                                       applicability of
                                                       experience to
                                                       saline
                                                       formations.
Acid gas injection..............  > 15 years          Generally small
                                   experience          volumes; very
                                   injecting CO2 and   little publicly
                                   H2S into over 44    available
                                   geologic            technical
                                   formations.         information.
Hazardous waste disposal/         ..................  Most hazardous
 underground injection control.                        waste is not
                                                       buoyant or
                                                       reactive.
Natural gas storage.............  100 years           Limited
                                   experience          monitoring;
                                   injecting natural   different
                                   gas into rocks.     chemistry; built
                                                       for temporary
                                                       storage.
Natural analogs.................  Several large (>    Most at steady
                                   50 trillion cubic   state, transient
                                   feet) carbo-        knowledge
                                   gaseous             unavailable;
                                   accumulations       limited geography
                                   globally; proof     and geology.
                                   of concept.
Conventional oil and gas E&P....  Nearly 150 years    Hydrocarbon
                                   of technology and   recovery has
                                   experience in       goals and needs
                                   predicting and      which differ from
                                   managing buoyant    those of carbon
                                   fluids in crust.    sequestration.
Capture/gas separations           > 70 years          Costs still higher
 technology.                       separating CO2      than preferred
                                   and other acid      under widespread
                                   gases from gas      deployment; still
                                   streams,            no integration of
                                   including at        large power
                                   power plants.       plants with CCS.
Large CO2 storage projects......  3 large-scale       Still limited
                                   projects; > 6       monitoring
                                   pending before      program; limited
                                   2010.               geologic
                                                       representation.
CO2 pipelines and transportation  > 30 years          None.
                                   experience at
                                   large scale;
                                   existing
                                   regulations
                                   likely to apply.
------------------------------------------------------------------------


       TABLE T-V.2.--SUMMARY OF CCS TECHNOLOGIES IN PRIORITY ORDER
------------------------------------------------------------------------
           Technology                Significance      Brief Discussion
------------------------------------------------------------------------
CO2-EOR.........................  Natural arena for   Provides a direct
                                   exploring CCS.      commercial
                                                       incentive to
                                                       pumping CO2 into
                                                       a reservoir.
Evaluation of CCS in association  Development of      Projects in USA,
 with coal-fired plant.            integration of      Australia and
                                   required            China to develop
                                   technologies.       CCS with coal
                                                       plant.
Improved capture technologies...  Key determinant of  Significant
                                   cost of CCS.        efforts in USA,
                                                       Europe and Japan
                                                       to drive down
                                                       cost of capture.
Injection of CO2 into subsurface  Demonstration of    CO2 currently
 formations.                       injection and       injected at the
                                   test of storage.    Mt/yr level.
Development of models for         Understanding of    Combination of
 migration of CO2 subsurface.      migration           modeling and
                                   behavior            experiment (e.g.
                                   underpins           Sleipner) to
                                   characterization    establish CO2
                                   and MMV.            migration.
Reservoir characterization for    Reservoir           Available
 storage.                          characterization    techniques tested
                                   techniques          at several sites.
                                   migrate to CO2
                                   storage estimates.
Measurement, monitoring and       Available MMV       Available
 verification (MMV).               technologies        techniques tested
                                   applied to CO2      at several sites.
                                   injection and
                                   storage.
Development of CO2 resistant ce-  Primary leakage     Improvements in
  ments.                           path is likely to   resistance of
                                   be existing wells.  cements to
                                                       corrosion are
                                                       currently being
                                                       pursued.
------------------------------------------------------------------------


 TABLE T-V.3.--SUMMARY OF CCS TECHNOLOGIES IN TIME/PRIORITY ORDER, WITH
                       TIMEFRAME TO COMMERCIAL USE
------------------------------------------------------------------------
             Technology                     Significance       Timeframe
------------------------------------------------------------------------
Extensive CO2-EOR with substantial    Enhanced security of         2010
 CO2 sequestra-  tion.                 supply through better
                                       recovery.
Measurement, monitoring and           Necessary prerequisite       2010
 verification (MMV) techniques.        for implementation.
Site characterization and risk        Determination of site        2010
 assessment.                           suitability for
                                       sequestration.
CO2 leak remediation technology.....  Necessary for                2010
                                       implementation of CO2
                                       storage.
Demonstration of coal-fired power     Establish precedent for      2010
 with CCS.                             the technology.
Assessment of U.S. CO2 sequestration  Primary requirement for    < 2020
 capacity.                             siting power stations.
Novel, inexpensive capture            Key cost determinant of    < 2020
 technology.                           CCS.
Next-generation CO2-EOR with maximum  Increases usable CO2         2020
 CO2 storage.                          storage capacity in
                                       structurally confined
                                       geologic settings by
                                       three- to ten-fold.
Ubiquitous coal-fired power with CCS  Extensive power              2020
                                       generation without CO2
                                       emissions.
Rig-site or sub-surface hydrocarbon   Keeps most of the            2030
 processing to generate low-carbon     carbon in or near the
 fuels or feedstocks and recycle CO2   reservoir, simplifying
 within the reservoir or field for     CCS logistics and
 EOR followed by CCS.                  costs, enabling low
                                       carbon fuels/heat/
                                       power from oil and gas.
------------------------------------------------------------------------

Summary--Nontechnical Issues
    Given the scope of commercial CCS, there are many issues that are 
not technical, per se, but relate to technical readiness and ways to 
maximize early investment:
  --There is a high likelihood of a critical gap in human capital. 
        Currently, workers who can execute CCS are the same as those 
        employed in oil and natural gas exploration and production. In 
        a carbon-constrained economy, there will not be enough skilled 
        workers to go around. This is particularly true for 
        geoscientists, but also true for chemical and mechanical 
        engineers.
  --Development of a comprehensive set of energy policies and 
        strategies is critical to provide certainty to make investment 
        decisions.
  --The legislative and regulatory framework within which CCS is 
        conducted will have a major impact on how rapidly the 
        technology is implemented and ultimately will determine whether 
        CCS can effectively mitigate carbon emissions and provide 
        access to future hydrocarbon supplies.
  --It is not clear that the science and technology programs in place 
        today will provide answers required by regulators and decision 
        makers. Greater dialogue between individuals working with 
        technology and those developing a regulatory framework would 
        help to reduce unnecessary regulation and guide R&D goals 
        toward the most immediate needs.
  --Infrastructure to transport CO2, such as pipelines, is 
        essential for commercial deployment. However, there is concern 
        that pipelines for early project opportunities will not be able 
        to carry additional future projects. Incentives and government 
        action for this infrastructure can help to build networks 
        sufficient to support large-scale, commercial CCS deployment in 
        the United States.
                              conclusions
    The challenges facing our energy future are daunting, but not 
insurmountable. Given the massive scale of the global energy system and 
the long lead times necessary to make significant changes, concerted 
actions are needed now to promote U.S. competitiveness by balancing 
economic, security, and environmental goals. Carbon dioxide emissions 
are by their very nature a global issue, and atmospheric concentrations 
respect no geographic boundary, as such, ultimately a global solution 
is required. Carbon capture and storage is in some ways a unique 
opportunity for the United States to both develop technology and 
demonstrate leadership. We have large remaining fossil fuel reserves 
which could be economically and environmentally converted using carbon 
capture technology and we have the infrastructure and sedimentary 
basins to sequester the CO2. The regulatory and legislative 
framework within which CCS is conducted will have a major impact on how 
rapidly the technology is implemented. The oil and gas industry has the 
skill sets to further develop and deploy this technology, but clearly 
cross industry and government cooperation is required. Thank you and I 
would be happy to answer any questions.

    Senator Dorgan. Mr. Nelson, thank you very much. Finally, 
we will hear from Jeffrey Phillips, who represents the Electric 
Power Research Institute in North Carolina.
STATEMENT OF JEFFREY N. PHILLIPS, PROGRAM MANAGER, 
            ELECTRIC POWER RESEARCH INSTITUTE
    Mr. Phillips. First of all, Mr. Chairman, I want to thank 
you for inviting me to speak on behalf of our Institute.
    As you know, I testified in front of the Senate Energy 
Committee on the topic of advanced coal-generation technology 
earlier this month, and at that time I made five points. 
Today's coal power plants are much cleaner and more efficient 
than the existing fleet. Today's CO2 capture 
technology will increase wholesale electricity prices by up to 
80 percent, but we've identified a clear technology development 
path that can greatly decrease the cost impact by 2025. 
Unfortunately, the funding for that development path is sadly 
inadequate. And, finally, we engineers need some legal experts 
to help us set out the rules for deep geologic storage of 
CO2.
    At this hearing I would like to expand on the technology 
development path that we've identified to decrease the cost of 
CO2 capture, as well as discuss the possibility of 
using the sale of captured CO2 for enhanced oil 
recovery as a means to accelerate deployment of carbon capture 
technology and coal power plants worldwide.
    In late 2004 EPRI initiated a new program called CoalFleet 
for Tomorrow, which is an industry-led effort aimed at 
accelerating the deployment of advanced coal power plant 
technology, particularly technology which can capture 
CO2. In less than 3 years CoalFleet has made 
significant progress, including the creation of what we call 
research development and demonstration (RD&D) augmentation 
plans for both combustion-based and IGCC power plants. The main 
goal of these plants is to have cost-effective carbon capture 
storage technology ready and proven at commercial scale in the 
2025 time frame. These plants identify the key actions that 
must take place that are not currently funded. More details of 
our RD&D augmentation plans can be found in my written 
testimony.
    We're also looking at coal drying and methods for 
mitigating the impact of high altitudes, as well as ways to 
decrease water use, all important aspects for the use of North 
Dakota lignite.
    CoalFleet is funded by more than 60 organizations, 
including power generators, equipment suppliers, oil companies, 
and government agencies, as well as coal and railroad 
companies. It provides a forum for all the key players in this 
field to discuss the issues and work together on RD&D to prove 
carbon capture and storage economics.
    I want to take this moment to publicly thank Great River 
Energy for its strong support of CoalFleet, and we would 
welcome the participation of other power generation and coal-
related organizations from North Dakota, as well as the other 
49 States.
    EPRI is already putting together action plans to implement 
demonstration projects in the CoalFleet RD&D plants. However, 
these projects will require significant amounts of money in 
order to move forward. One way to offset the cost of these 
demonstration projects would be to sell captured CO2 
to the oil industry for enhanced oil recovery.
    Recent studies by the U.S. Department of Energy reveal the 
potential market for up to 17.5 billion tons of CO2 
for enhanced oil recovery. In theory at least this is enough 
CO2--this CO2 could be provided by 180 
coal powerplants, each 500 megawatts, capturing 90 percent of 
their CO2 over a 30-year period. That's a lot of new 
coal powerplants. Now, it's as much as the U.S. Department of 
Energy's energy information predicts will be built between now 
and 2025. And the thing that I find most amazing is if we did 
this, we would double domestic oil production. I repeat we 
would double domestic oil production. Of course, not all the 
new coal powerplants are going to be in areas where the oil 
industry needs CO2, but some are, and even if we 
could just get 10 percent of these plants built with 
CO2 capture that would give us 18 opportunities to 
build large-scale CO2 capture facilities. And the 
history of other powerplant technologies tells us that the 18th 
facility will cost a lot less than the first one, which means 
that if we and the rest of the world have to build 
CO2 capture facilities on all new coal powerplants, 
they will cost a lot less than they would if we miss this win-
win opportunity.
    I must point out even if oil companies were willing to pay 
$15 to $25 per ton for CO2, that would not cover the 
full cost of capturing CO2 from a coal power plant 
with today's technology, whether it's IGCC or oxy-firing. 
Consequently, we will have to come up with some way to 
subsidize the cost of capturing CO2 in order to make 
it attractive.
    Our CoalFleet program has also identified other non-
technology-related impediments to deploying coal power based 
EOR projects, which I would be happy to discuss further during 
the question and answer period, as well as any other questions 
you have.

                           PREPARED STATEMENT

    Finally, let me point out, if we develop and demonstrate 
carbon capture and storage here in the United States, the 
technology will be applied--could be applied worldwide, thereby 
providing additional leverage for R&D funds, creating 
international markets for U.S. technology and having a 
significant impact on global warming. That concludes my 
testimony.
    [The statement follows:]
            Prepared Statement of Jeffrey N. Phillips, Ph.D.
Introduction
    I am Jeff Phillips, Program Manager for Advanced Coal Generation 
for the Electric Power Research Institute (EPRI). EPRI is a non-profit, 
collaborative R&D organization with principal offices in Palo Alto, 
California; Knoxville, Tennessee; and Charlotte, North Carolina, where 
I work. EPRI appreciates the opportunity to provide testimony to the 
subcommittee on the topic of coal research, development, and 
demonstration (RD&D) as well as the potential benefits if the coal, 
oil, and gas industries were to work together to sequester carbon and 
enhance domestic oil production.
    The key points I will make today include:
  --Advanced coal power plant technologies with integrated 
        CO2 capture and storage (CCS) will be crucial to 
        lowering U.S. electric power sector CO2 emissions to 
        1990 levels by 2030. They will also be crucial to substantially 
        lowering world CO2 emissions as well.
  --Without advanced coal power and integrated CCS technologies, the 
        cost of electric power will increase dramatically, and the 
        impact on the U.S. economy could reach $1 trillion per year by 
        2030.
  --EPRI's CoalFleet for Tomorrow program has identified the RD&D 
        pathways to demonstrate, by 2025, a full portfolio of 
        economically attractive, commercial-scale advanced coal power 
        and integrated CCS technologies suitable for use with the broad 
        range of U.S. coal types.
  --The identified RD&D will cost $8 billion between now and 2017 and 
        $17 billion cumulatively by 2025, and we need to begin 
        immediately to ensure that these climate change solution 
        technologies will be fully tested at scale by 2025.
  --Selling CO2 captured from coal power plants for EOR 
        could lower the cost of testing CO2 capture 
        technology and would have the added benefit of increasing U.S. 
        oil production.
  --The U.S. Department of Energy has identified a potential EOR market 
        for up to $17.5 billion tons of CO2, which is equal 
        to the 30-year cumulative CO2 production of 180 coal 
        power plants sized at 500 MW; however, a number of potential 
        barriers need to be addressed before any such plants could 
        become a reality, including regulatory and long-term liability 
        issues.
                         summary of key points
    Coal is the energy source for half of the electricity generated in 
the United States. Even with the aggressive development and deployment 
of alternative energy sources, numerous forecasts of energy use predict 
that coal will continue to provide a major share of our electric power 
generation throughout the 21st century. Coal is a stably priced, 
affordable, domestic fuel that can be used in an environmentally 
responsible manner. Criteria air pollutants from all types of new coal 
power plants have been reduced by more than 90 percent compared with 
plants built 40 years ago. Through the development and deployment of 
advanced coal plants with integrated CO2 capture and storage 
(CCS) technologies, coal power will become part of the solution to 
satisfying both our energy needs and our global climate change 
concerns. However, a sustained RD&D program at heightened levels of 
investment and resolution of legal and regulatory unknowns for long-
term geologic CO2 storage will be required to achieve the 
promise of clean coal technologies. The members of EPRI's CoalFleet for 
Tomorrow program--a research collaborative comprising more than 60 
organizations representing international power generators, equipment 
suppliers, government research organizations, coal and oil companies, 
and a railroad--see crucial roles for both industry and governments 
worldwide in aggressively pursuing collaborative RD&D over the next 20+ 
years to create a full portfolio of commercially self-sustaining, 
competitive advanced coal power generation and CO2 capture 
and storage technologies.
    The potential return on this investment is enormous. EPRI's 
``Electricity Technology in a Carbon-Constrained Future'' study 
suggests that it is technically feasible to reduce U.S. electric sector 
CO2 emissions over the next 25 years while meeting the 
increased demand for electricity. The study showed that the largest 
single contributor to emissions reduction would come from the 
integration of CCS technologies to advanced coal-based power plants 
coming on-line after 2020. Economic analyses of scenarios to achieve 
the study's emission reduction goals show that a 2030 U.S. energy mix 
including advanced coal technologies with integrated CCS results in 
electricity at half the cost of a 2030 energy mix without advanced coal 
with CCS. In the case with advanced coal with CCS, the U.S. economy is 
$1 trillion per year larger than in the case without advanced coal and 
CCS, with a much stronger manufacturing sector. A previous EPRI 
economic study based on financial market ``options'' principles found a 
similarly large benefit to U.S. consumers of having coal's price-
stabilizing influence on the electricity system.
    The portfolio aspect of advanced coal with integrated CCS 
technologies must be emphasized because no single advanced coal 
technology (or any generating technology) has clear-cut economic 
advantages across the range of U.S. applications. The best strategy for 
meeting future electricity needs while addressing climate change 
concerns and minimizing economic disruption lies in developing a full 
portfolio of technologies from which power producers (and their 
regulators) can choose the option best suited to local conditions and 
preferences and provide power at the lowest cost to the customer. When 
it comes to advanced coal with integrated CCS technologies, there is no 
``silver bullet,'' but we can develop ``silver buckshot.''
    Toward this end, four major technology efforts related to 
CO2 emissions reduction from coal-based power systems must 
be undertaken:
  --Increased efficiency and reliability of integrated gasification 
        combined cycle (IGCC) power plants;
  --Increased thermodynamic efficiency of pulverized-coal (PC) power 
        plants;
  --Improved technologies for capture of CO2 from coal 
        combustion- and gasification-based power plants; and
  --Reliable, acceptable technologies for long-term storage of captured 
        CO2.
    Identification of mechanisms to share RD&D financial and technical 
risks and to address legal and regulatory uncertainties must take place 
as well.
    In short, a comprehensive recognition of all the factors needed to 
hasten deployment of competitive, commercial advanced coal and 
integrated CO2 capture and storage technologies--and 
implementation of realistic, pragmatic plans to overcome barriers--is 
the key to meeting the challenge to supply affordable, environmentally 
responsible energy in a carbon-constrained world.
  accelerating rd&d on advanced coal technologies with co2 
         capture and storage--investment and time requirements
    A typical path to develop a technology to commercial maturity 
consists of moving from the conceptual stage to laboratory testing, to 
small pilot-scale tests, to larger-scale tests, to multiple full-scale 
demonstrations, and finally to deployment in full-scale commercial 
operations. For capital-intensive technologies such as advanced coal 
power systems, each stage can take years or even decades to complete 
and each sequential stage tends to entail increasing levels of 
investment. As depicted in Figure 1, several key advanced coal power 
and CCS technologies are now in (or approaching) an ``adolescent'' 
stage of development. This is a time of particular vulnerability in the 
technology development cycle, as it is common for the expected costs of 
full-scale application to be higher than earlier estimates when less 
was known about scale-up and application challenges. Public agency and 
private funders can become disillusioned with a technology development 
effort at this point, but as long as fundamental technology performance 
results continue to meet expectations, and a path to cost reduction is 
clear, perseverance by project sponsors in maintaining momentum is 
crucial.
    Unexpectedly high costs at the mid-stage of technology development 
have historically come down following market introduction, experience 
gained from ``learning-by-doing,'' realization of economies of scale in 
design and production as order volumes rise, and removal of 
contingencies covering uncertainties and first-of-a-kind costs. An 
International Energy Agency study led by Carnegie Mellon University 
observed this pattern in the cost-over-time of power plant 
environmental controls and has predicted a similar reduction in the 
cost of power plant CO2 capture technologies as the 
cumulative installed capacity grows.\1\ EPRI concurs with their 
expectations of experience-based cost reductions and believes that RD&D 
on specifically identified technology refinements can lead to greater 
cost reductions sooner in the deployment phase.
---------------------------------------------------------------------------
    \1\ IEA Greenhouse Gas R&D Programme (IEA GHG), ``Estimating Future 
Trends in the Cost of CO2 Capture Technologies,'' 2006/5, 
January 2006.

[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]

    Of the coal-based power generating and carbon sequestration 
technologies shown in Figure 1, only supercritical pulverized coal 
(SCPC) technology has reached commercial maturity. It is crucial that 
other technologies in the portfolio--namely ultra-supercritical (USC) 
PC, integrated gasification combined cycle (IGCC), CO2 
capture (pre-combustion, post-combustion, and oxy-combustion), and 
CO2 storage--be given sufficient support to reach the stage 
of declining constant dollar costs before society's requirements for 
greenhouse gas reductions compel their application in large numbers.
    Figure 2 depicts the major activities in each of the four 
technology areas that must take place to achieve a set of robust 
solutions to reduce CO2 emissions from coal power systems. 
This framework should be considered as a whole rather than as a set of 
discrete tasks. Although individual goals related to efficiency, 
CO2 capture, and CO2 storage present major 
challenges, significant challenges also arise from complex interactions 
that occur when CO2 capture processes are integrated with 
gasification- and combustion-based power plant processes.

[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]

  reducing co2 emissions through improved coal power plant 
                               efficiency
    Improved thermodynamic efficiency reduces CO2 emissions 
by reducing the amount of fuel required to generate a given amount of 
electricity. A two-percentage point gain in efficiency provides a 
reduction in fuel consumption of roughly 5 percent and a similar 
reduction in CO2 output. Depending on the technology used, 
improved efficiency can also provide similar reductions in criteria air 
pollutants, hazardous air pollutants, and water consumption.
    A ``typical'' 500 MW (net) coal plant emits about 3 million metric 
tons of CO2 per year. The annual power output and emissions 
of the current U.S. coal fleet are roughly equivalent to 600 such 
plants. The contributions attributable to individual plants vary 
considerably with differences in plant steam cycle, coal type, capacity 
factor, and operating regimes. For a given fuel, a new supercritical PC 
unit built today might produce 5-10 percent less CO2 per 
megawatt-hour (MWh) than the existing fleet average for that coal type.
    With an aggressive RD&D program on efficiency improvement, new 
ultra-supercritical (USC PC) plants could reduce CO2 
emissions per MWh by up to 25 percent relative to the existing fleet 
average. Significant efficiency gains are also possible for IGCC plants 
by employing advanced gas turbines and through more energy-efficient 
oxygen plants and synthesis (fuel) gas cleanup technologies.
    EPRI and the Coal Utilization Research Council (CURC), in 
consultation with DOE, have identified a challenging but achievable set 
of milestones for improvements in the efficiency, cost, and emissions 
of PC and coal-based IGCC plants. The EPRI-CURC Roadmap projects an 
overall improvement in the thermal efficiency of state-of-the-art 
generating technology from 38-41 percent in 2010 to 44-49 percent by 
2025 (on a higher heating value [HHV] basis; see Table 1). The ranges 
in the numbers are not simply a reflection of uncertainty, but rather 
they underscore an important point about differences among U.S. coals. 
The natural variations in moisture and ash content and combustion 
characteristics between coals have a significant impact on attainable 
efficiency.
    An advanced coal plant firing North Dakota lignite, for example, 
would likely have an HHV efficiency two percentage points lower than 
the efficiency of a comparable plant firing subbituminous coal from 
Wyoming and Montana's Powder River basin. Similarly, plants using 
Powder River Basin coal would have efficiencies about two percentage 
points lower than plants firing Appalachian bituminous coals. Any 
government incentive program with an efficiency-based qualification 
criterion should recognize these inherent differences in the attainable 
efficiencies for plants using different ranks of coal.
    As Table 1 indicates, technology-based efficiency gains over time 
will be offset by the energy required for CO2 capture. 
Nevertheless, aggressive pursuit of the EPRI-CURC RD&D program offers 
the prospect of coal plants with CO2 capture in 2025 that 
have net efficiencies meeting or exceeding current-day power plants 
without CO2 capture.

                              TABLE 1.--EFFICIENCY MILESTONES IN EPRI-CURC ROADMAP
----------------------------------------------------------------------------------------------------------------
                                         2010                2015                2020                2025
----------------------------------------------------------------------------------------------------------------
PC & IGCC Systems (Without CO2     38-41 percent HHV   39-43 percent HHV   42-46 percent HHV   44-49 percent HHV
 Capture).......................
PC & IGCC Systems (With CO2        31-32 percent HHV   31-35 percent HHV   33-39 percent HHV   39-46 percent HHV
 Capture \1\)...................
----------------------------------------------------------------------------------------------------------------
\1\ Efficiency values reflect impact of 90 percent CO2 capture, but not compression or transportation.

                new plant efficiency improvements--igcc
    Although IGCC is not yet a mature technology for coal-fired power 
plants, chemical plants around the world have accumulated a 100-year 
experience base operating coal-based gasification units and related gas 
cleanup processes. The most advanced of these units are similar to the 
front end of a modern IGCC facility. Similarly, several decades of 
experience firing natural gas and petroleum distillate have established 
a high level of maturity for the basic combined cycle generating 
technology. Nonetheless, ongoing RD&D continues to provide significant 
advances in the base technologies, as well as in the suite of 
technologies used to integrate them into an IGCC generating facility.
    Efficiency gains in currently proposed IGCC plants will come from 
the use of new ``FB-class'' gas turbines, which will provide an overall 
plant efficiency gain of about 0.6 percentage point (relative to IGCC 
units with FA-class models, such as Tampa Electric's Polk Power 
Station). This corresponds to a decrease in CO2 emissions 
rate of about 1.5 percent.
    Figure 3 depicts the anticipated timeframe for further developments 
identified by EPRI's CoalFleet for Tomorrow program that promise a 
succession of significant improvements in IGCC unit efficiency. Key 
technology advances under development include:
  --larger capacity gasifiers (often via higher operating pressures 
        that boost throughput without a commensurate increase in vessel 
        size);
  --integration of new gasifiers with larger, more efficient G- and H-
        class gas turbines;
  --use of ion transport membrane (ITM) and/or other more energy-
        efficient technologies in oxygen plants;
  --warm synthesis gas cleanup and membrane separation processes for 
        CO2 capture that reduce energy losses in these 
        areas;
  --recycle of liquefied CO2 to replace water in gasifier 
        feed slurry (reducing heat loss to water evaporation); and
  --hybrid combined cycles using fuel cells to achieve generating 
        efficiencies exceeding those of conventional combined cycle 
        technology.
    Improvements in gasifier reliability and in control systems also 
contribute to improved annual average efficiency by minimizing the 
number and duration of startups and shutdowns. 

[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]

    Counteracting Gas Turbine Output Loss at High Elevations.--IGCC 
plants designed for application in the western Great Plains and 
Intermountain West must account for the natural reduction in gas 
turbine power output that occurs where the air is thin. This phenomenon 
is rooted in the fundamental volumetric flow limitation of a gas 
turbine, and can reduce power output by up to 15 percent at an 
elevation of 5,000 feet (relative to a comparable plant at sea level). 
EPRI is exploring measures to counteract this power loss, including 
inlet air chilling (a technique used at natural gas power plants to 
mitigate the power loss that comes from thinning of the air on a hot 
day) and use of supplemental burners between the gas turbine and steam 
turbine to boost the plant's steam turbine section generating capacity.
    Larger, Higher Firing Temperature Gas Turbines.--For plants coming 
on-line around 2015, the larger size G-class gas turbines, which 
operate at higher firing temperatures (relative to F-class machines) 
can improve efficiency by 1 to 2 percentage points while also 
decreasing capital cost per kW capacity. The H-class gas turbines, 
coming on-line in the same timeframe, will provide a further increase 
in efficiency and capacity.
    Ion Transport Membrane-Based Oxygen Plants.--Most gasifiers used in 
IGCC plants require a large quantity of high-pressure, high purity 
oxygen, which is typically generated on site with an expensive and 
energy-intensive cryogenic process. The ITM process allows the oxygen 
in high-temperature air to pass through a membrane while preventing 
passage of non-oxygen atoms. According to developers, an ITM-based 
oxygen plant consumes 35-60 percent less power and costs 35 percent 
less than a cryogenic plant. EPRI is performing a due diligence 
assessment of this technology in advance of potential participation in 
technology scale-up efforts.
    Supercritical Heat Recovery Steam Generators.--In IGCC plants, hot 
exhaust gas exiting the gas turbine is ducted into a heat exchanger 
known as a heat recovery steam generator (HRSG) to transfer energy into 
water-filled tubes producing steam to drive a steam turbine. This 
combination of a gas turbine and steam turbine power cycles produces 
electricity more efficiently than either a gas turbine or steam turbine 
alone. As with conventional steam power plants, the efficiency of the 
steam cycle in a combined cycle plant increases when turbine inlet 
steam temperature and pressure are increased. The higher exhaust 
temperatures of G- and H-class gas turbines offer the potential for 
adoption of more-efficient supercritical steam cycles. Materials for 
use in a supercritical HRSG are generally established.
    Synthesis Gas Cleaning at Higher Temperatures.--The acid gas 
recovery (AGR) processes currently used to remove sulfur compounds from 
synthesis gas require that the gas and solvent be cooled to about 100 
F, thereby causing a loss in efficiency. Further costs and efficiency 
loss are inherent in the process equipment and auxiliary steam required 
to recover the sulfur compounds from the solvent and convert them to 
useable products. Several DOE-sponsored RD&D efforts aim to reduce the 
energy losses and costs imposed by this recovery process. These 
technologies (described below) could be ready--with adequate RD&D 
support--by 2020:
  --The Selective Catalytic Oxidation of Hydrogen Sulfide process 
        eliminates the Claus and Tail Gas Treating units, along with 
        the traditional solvent-based AGR contactor, regenerator, and 
        heat exchangers, by directly converting hydrogen sulfide 
        (H2S) to elemental sulfur. The process allows for a 
        higher operating temperature of approximately 300 F, which 
        eliminates part of the low-temperature gas cooling train. The 
        anticipated benefit is a net capital cost reduction of about 
        $60/kW along with an efficiency gain of about 0.8 percentage 
        point.
  --The RTI/Eastman High Temperature Desulfurization System uses a 
        regenerable dry zinc oxide sorbent in a dual loop transport 
        reactor system to convert H2S and COS to 
        H2O, CO2, and SO2. Tests at 
        Eastman Chemical Company have shown sulfur species removal 
        rates above 99.9 percent, with 10 ppm output versus 8,000+ ppm 
        input sulfur, using operating temperatures of 800-1,000 F. 
        This process is also being tested for its ability to provide a 
        high-pressure CO2 by-product. The anticipated 
        benefit for IGCC, compared with using a standard oil-industry 
        process for sulfur removal, is a net capital cost reduction of 
        $60-$90 per kW, a thermal efficiency gain of 2-4 percent for 
        the gasification process, and a slight reduction in operating 
        cost. Tests are also under way for a multi-contaminant removal 
        processes that can be integrated with the transport 
        desulfurization system at temperatures above 480 F.
    Liquid CO2-Coal Slurrying for Gasification of Low-Rank 
Coals.--Future IGCC plants may recycle some of the recovered liquid 
CO2 to replace water as the slurrying medium for the coal 
feed. This is expected to increase gasification efficiency for all 
coals, but particularly for subbituminous coal and lignite, which have 
naturally high moisture contents. The liquid CO2 has a lower 
heat of vaporization than water and is able to carry more coal per unit 
mass of fluid. The liquid CO2-coal slurry will flash almost 
immediately upon entering the gasifier, providing good dispersion of 
the coal particles and potentially yielding the higher performance of a 
dry-fed gasifier with the simplicity of a slurry-fed system.
    Traditionally, slurry-fed gasification technologies have a cost 
advantage over conventional dry-fed fuel handling systems, but they 
suffer a large performance penalty when used with coals containing a 
large fraction of water and ash. EPRI identified CO2 coal 
slurrying as an innovative fuel preparation concept 20 years ago, when 
IGCC technology was in its infancy. At that time, however, the cost of 
producing liquid CO2 was too high to justify the improved 
thermodynamic performance.
    To date, CO2-coal slurrying has only been demonstrated 
at pilot scale and has yet to be assessed in feeding coal to a 
gasifier, so the estimated performance benefits remain to be confirmed. 
The concept warrants consideration for future IGCC plants that capture 
and compress CO2 for storage, as this will substantially 
reduce the incremental cost of producing a liquid CO2 
stream. It will first be necessary, however, to update previous studies 
to quantify the potential benefit of liquid CO2 slurries 
with IGCC plants designed for CO2 capture. If the predicted 
benefit is economically advantageous, a significant amount of scale-up 
and demonstration work would be required to qualify this technology for 
commercial use.
    Fuel Cells and IGCC.--No matter how far gasification and turbine 
technologies advance, IGCC power plant efficiency will never progress 
beyond the inherent thermodynamic limits of the gas turbine and steam 
turbine power cycles (along with lower limits imposed by available 
materials technology). Several IGCC-fuel cell hybrid power plant 
concepts (IGFC) aim to provide a path to coal-based power generation 
with net efficiencies that exceed those of conventional combined cycle 
generation.
    Along with its high thermal efficiency, the fuel cell hybrid cycle 
reduces the energy consumption for CO2 capture. The anode 
section of the fuel cell produces a stream that is highly concentrated 
in CO2. After removal of water, this stream can be 
compressed for sequestration. The concentrated CO2 stream is 
produced without having to include a water-gas shift reactor in the 
process (see Figure 4). This further improves the thermal efficiency 
and decreases capital cost. IGFC power systems are a long-term 
solution, however, and are unlikely to see full-scale demonstration 
until about 2030.

[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]


    Role of FutureGen.--The FutureGen Industrial Alliance and DOE are 
building a first-of-its-kind, near-zero emissions coal-fed IGCC power 
plant integrated with CCS. The commencement of full-scale operations is 
targeted for 2013. The project aims to sequester CO2 in a 
representative geologic formation at a rate of at least one million 
metric tons per year.
    The FutureGen design will address scaling and integration issues 
for coal-based, zero emissions IGCC plants. In its role as a ``living 
laboratory,'' FutureGen is designed to validate additional advanced 
technologies that offer the promise of clean environmental performance 
at a reduced cost and increased reliability. FutureGen will have the 
flexibility to conduct full-scale and slipstream tests of such scalable 
advanced technologies as:
  --Membrane processes to replace cryogenic separation for oxygen 
        production;
  --An advanced transport reactor sidestream with 30 percent of the 
        capacity of the main gasifier;
  --Advanced membrane and solvent processes for H2 and 
        CO2 separation;
  --A raw gas shift reactor that reduces the upstream clean-up 
        requirements;
  --Ultra-low-NOX combustors that can be used with high-
        hydrogen synthesis gas;
  --A fuel cell hybrid combined cycle pilot;
  --Challenging first-of-a-kind system integration; and
  --Smart dynamic plant controls including a CO2 management 
        system.
    Figure 5 provides a schematic of the ``backbone'' and ``research 
platform'' process trains envisioned for the FutureGen plant.

[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]

    Figure 6 summarizes EPRI's recommended major RD&D activities for 
improving the efficiency and cost of IGCC technologies with 
CO2 capture.

[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]

      new plant efficiency improvements--advanced pulverized coal
    Pulverized-coal power plants have long been a primary source of 
reliable and affordable power in the United States and around the 
world. The advanced level of maturity of the technology, along with 
basic thermodynamic principles, suggests that significant efficiency 
gains can most readily be realized by increasing the operating 
temperatures and pressures of the steam cycle. Such increases, in turn, 
can be achieved only if there is adequate development of suitable 
materials and new boiler and steam turbine designs that allow use of 
higher steam temperatures and pressures.
    Current state-of-the-art plants use supercritical main steam 
conditions (i.e., temperature and pressure above the ``critical point'' 
where the liquid and vapor phases of water are indistinguishable). SCPC 
plants typically have main steam conditions up to 1100 F. The term 
``ultra-supercritical'' is used to describe plants with main steam 
temperatures in excess of 1100 F and potentially as high as 1400 F.
    Achieving higher steam temperatures and higher efficiency will 
require the development of new corrosion-resistant, high-temperature 
nickel alloys for use in the boiler and steam turbine. In the United 
States, these challenges are being addressed by the Ultra-Supercritical 
Materials Consortium, a DOE R&D program involving Energy Industries of 
Ohio, EPRI, the Ohio Coal Development Office, and numerous equipment 
suppliers. EPRI provides technical management for the consortium. 
Results are applicable to all ranks of coal.
    It is expected that a USC PC plant operating at about 1300 F will 
be built during the next 7 to 10 years, following the demonstration and 
commercial availability of advanced materials from these programs. This 
plant would achieve an efficiency of about 43 percent (HHV) on 
subbituminous coal, compared with 37 percent for a current state-of-
the-art plant, and would reduce CO2 production per net MWh 
by about 15 percent.
    Ultimately, nickel-base alloys are expected to enable stream 
temperatures in the neighborhood of 1400 F and generating efficiencies 
up to 45 percent HHV with subbituminous coal. This approximately 10 
percentage point improvement over the efficiency of a new subcritical 
pulverized-coal plant would equate to a decrease of about 25 percent in 
CO2 and other emissions per MWh.
    Figure 7 illustrates a timeline developed by EPRI's CoalFleet for 
Tomorrow program to establish efficiency improvement and cost 
reduction goals for USC PC plants with CO2 capture.

[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]


    UltraGen USC PC Commercial Projects.--EPRI and industry 
representatives have proposed a framework to support commercial 
projects that demonstrate advanced PC technologies. The vision entails 
construction of two commercially operated USC PC power plants that 
combine state-of-the-art pollution controls, ultra-supercritical steam 
power cycles, and innovative flue gas scrubbing technologies to capture 
CO2.
    The UltraGen I plant will use the best of today's proven ferritic 
steels, while UltraGen II will be the first plant in the United States 
to feature new, nickel-based alloys that are able to withstand the 
higher temperatures involved.
    UltraGen I will feature an approximately quarter-scale 
CO2 capture system demonstration using the best established 
technology. This system will be about 15 times the size of the largest 
system operating on a coal-fired boiler today. UltraGen II will double 
the size of the CO2 capture system, and may demonstrate a 
new class of chemical solvent if one of the emerging low-energy 
processes has reached a sufficient stage of development. Both plants 
will demonstrate ultra-low emissions. Both UltraGen demonstration 
plants will dry and compress the captured CO2 for long-term 
geologic storage and/or use in enhanced oil or gas recovery operations. 
Figure 8 depicts the proposed key features of UltraGen I and II.

[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]


    To provide a platform for testing and developing emerging PC 
technologies, the program will allow for technology trials at existing 
sites as well as at the sites of new projects. EPRI expects the 
UltraGen projects will be commercially operated units dispatching 
electricity to the grid. The differential cost to the host utility for 
demonstrating these improved features are envisioned to be offset by 
tax credits and funds raised by an industry-led consortia formed 
through EPRI.
    The UltraGen projects represent the type of ``giant step'' 
collaborative efforts that need to be taken to advance PC technology to 
the next phase of evolution and assure competitiveness in a carbon-
constrained world. Because of the time and expense for each ``design 
and build'' iteration for coal power plants (3 to 5 years not counting 
the permitting process and $2 billion), there is no room for hesitation 
in terms of commitment to advanced technology validation and 
demonstration projects.
    The UltraGen projects will resolve critical barriers to the 
deployment of USC PC technology by providing a shared-risk vehicle for 
testing and validating high-temperature materials, components, and 
designs in plants also providing superior environmental performance.
    Figure 9 summarizes EPRI's recommended major RD&D activities for 
improving the efficiency and cost of USC PC technologies with 
CO2 capture.

[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]


    Efficiency Gains for the Existing PC Fleet.--Many subcritical units 
in the existing U.S. fleet will continue to operate for years to come. 
Replacing these units en masse would be economically prohibitive. Their 
flexibility for load following and provision of support services to 
ensure grid stability makes them highly valuable. With equipment 
upgrades, many of these units can realize modest efficiency gains, 
which, when accumulated across the existing generating fleet could make 
a sizeable difference.
    These upgrades depend on the equipment configuration and operating 
parameters of a particular plant and may include:
  --turbine blading and steam path upgrades;
  --turbine control valve upgrades for more efficient regulation of 
        steam;
  --cooling tower and condenser upgrades to reduce circulating water 
        temperature, steam turbine exhaust backpressure, and auxiliary 
        power consumption;
  --cooling tower heat transfer media upgrades;
  --condenser optimization to maximize heat transfer and minimize 
        condenser temperature;
  --condenser air leakage prevention/detection;
  --variable speed drive technology for pump and fan motors to reduce 
        power consumption;
  --air heater upgrades to increase heat recovery and reduce leakage;
  --advanced control systems incorporating neural nets to optimize 
        temperature, pressure, and flow rates of fuel, air, flue gas, 
        steam, and water;
  --optimization of water blowdown and blowdown energy recovery;
  --optimization of attemperator design, control, and operating 
        scenarios;
  --sootblower optimization via ``intelligent'' sootblower system use; 
        and
  --coal drying (for plants using lignite and subbituminous coals).
    Coal Drying for Increased Generating Efficiency.--Boilers designed 
for high-moisture North Dakota lignite have traditionally employed 
higher feed rates (lb/hr) to account for the large latent heat load to 
evaporate fuel moisture. An innovative concept developed by Great River 
Energy (GRE) and Lehigh University uses low-grade heat recovered from 
within the plant to dry incoming fuel to the boiler, thereby boosting 
plant efficiency and output. [In contrast, traditional thermal drying 
processes are complex and require high-grade heat to remove moisture 
from the coal.] Specifically, the GRE approach uses steam condenser and 
boiler exhaust heat exchangers to heat air and water fed a fluidized-
bed coal dryer upstream of the plant pulverizers. Based on successful 
tests with a pilot-scale dryer and more than a year of continuous 
operation with a prototype dryer at its Coal Creek station, GRE (with 
U.S. Department of Energy support and EPRI technical consultation) is 
now building a full suite of dryers for Unit 2 (i.e., a commercial-
scale demonstration). In addition to the efficiency benefits from 
reducing the lignite feed moisture content by about 25 percent, the 
plant's air emissions will be reduced as well.\2\
---------------------------------------------------------------------------
    \2\ C. Bullinger, M. Ness, and N. Sarunac, ``One Year of Operating 
Experience with Prototype Fluidized Bed Coal Dryer at Coal Creek 
Generating Station,'' 32nd International Technical Conference on Coal 
Utilization and Fuel Systems, Clearwater FL, June 10-15, 2007.
---------------------------------------------------------------------------
             improving co2 capture technologies
    The laws of physics and chemistry impose inherent limits on the 
extent of CO2 reductions that can be achieved through 
efficiency gains alone. Further reductions in CO2 emissions 
will require pre-combustion or post-combustion CO2 capture 
technologies and the storage of separated CO2 in locations 
where it can be kept away from the atmosphere for centuries or longer.
    Albeit at considerable cost, CO2 capture technologies 
can be integrated into all coal-based power plant technologies. For 
existing plants, specific plant design features, space limitations, and 
various economic and regulatory considerations will determine whether 
retrofit-for-capture is feasible. For both new plants and retrofits, 
there is a tremendous need (and opportunity) to reduce the energy 
required to remove CO2 from fuel gas or flue gas. Figure 10 
shows a selection of the key technology developments and test programs 
needed to achieve commercial CO2 capture technologies for 
advanced coal combustion- and gasification-based power plants at a 
progressively shrinking constant-dollar levelized cost-of-electricity 
premium. Specifically, the target is a premium of about $6/MWh in 2025 
(relative to plants at that time without capture) compared with an 
estimated 2010 cost premium of perhaps $40/MWh (not counting the cost 
of transportation and storage). Such a goal poses substantial 
engineering challenges and will require major investments in RD&D to 
reduce the currently large net power reductions and efficiency 
(operating cost) penalties associated with CO2 capture 
technologies. Achieving this goal will allow power producers to meet 
the public demand for stable electricity prices while reducing 
CO2 emissions to address climate change concerns.

[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]

              pre-combustion co2 capture (igcc)
    IGCC technology allows for CO2 capture to take place via 
an added fuel gas processing step at elevated pressure, rather than at 
the atmospheric pressure of post-combustion flue gas, permitting 
capital savings through smaller equipment sizes as well as lower 
operating costs.
    Currently available technologies for such pre-combustion 
CO2 removal use a chemical and/or physical solvent that 
selectively absorbs CO2 and other ``acid gases,'' such as 
hydrogen sulfide. Application of this technology requires that the CO 
in synthesis gas (the principal component) first be ``shifted'' to 
CO2 and hydrogen via a catalytic reaction with water. The 
CO2 in the shifted synthesis gas is then removed via contact 
with the solvent in an absorber column, leaving a hydrogen-rich 
synthesis gas for combustion in the gas turbine. The CO2 is 
released from the solvent in a regeneration process that typically 
reduces pressure and/or increases temperature.
    Chemical plants currently employ such a process commercially using 
methyl diethanolamine (MDEA) as a chemical solvent or the Selexol and 
Rectisol processes, which rely on physical solvents. Physical solvents 
are generally preferred when extremely high (>99.8 percent) sulfur 
species removal is required. Although the required scale-up for IGCC 
power plant applications is less than that needed for scale-up of post-
combustion CO2 capture processes for PC plants, considerable 
engineering challenges remain and work on optimal integration with IGCC 
cycle processes has just begun.
    The impact of current pre-combustion CO2 removal 
processes on IGCC plant thermal efficiency and capital cost is 
significant. In particular, the water-gas shift reaction reduces the 
heating value of synthesis gas fed to the gas turbine. Because the 
gasifier outlet ratios of CO to methane to H2 are different 
for each gasifier technology, the relative impact of the water-gas 
shift reactor process also varies. In general, however, it can be on 
the order of a 10 percent fuel energy reduction. Heat regeneration of 
solvents further reduces the steam available for power generation. 
Other solvents, which are depressurized to release captured 
CO2, must be re-pressurized for reuse. Cooling water 
consumption is increased for solvents needing cooling after 
regeneration and for pre-cooling and interstage cooling during 
compression of separated CO2 to a supercritical state for 
transportation and storage. Heat integration with other IGCC cycle 
processes to minimize these energy impacts is complex and is currently 
the subject of considerable RD&D by EPRI and others.
    Membrane CO2 Separation.--Technology for separating 
CO2 from shifted synthesis gas (or flue gas from PC plants) 
offers the promise of lower auxiliary power consumption but is 
currently only at the laboratory stage of development. Several 
organizations are pursuing different approaches to membrane-based 
applications. In general, however, CO2 recovery on the low-
pressure side of a selective membrane can take place at a higher 
pressure than is now possible with solvent processes, reducing the 
subsequent power demand for compressing CO2 to a 
supercritical state. Membrane-based processes can also eliminate steam 
and power consumption for regenerating and pumping solvent, 
respectively, but they require power to create the pressure difference 
between the source gas and CO2-rich sides. If membrane 
technology can be developed at scale to meet performance goals, it 
could enable up to a 50 percent reduction in capital cost and auxiliary 
power requirements relative to current CO2 capture and 
compression technology.
       post-combustion co2 capture (pc and cfb plants)
    The post-combustion CO2 capture processes envisioned for 
power plant boilers draw upon commercial experience with amine solvent 
separation at much smaller scale in the food and beverage and chemical 
industries and upon three applications of CO2 capture from a 
slipstream of exhaust gas from circulating fluidized-bed (CFB) units.
    These processes contact flue gas with an amine solvent in an 
absorber column (much like a wet SO2 scrubber) where the 
CO2 chemically reacts with the solvent. The CO2-
rich liquid mixture then passes to a stripper column where it is heated 
to change the chemical equilibrium point, releasing the CO2. 
The ``regenerated'' solvent is then recirculated back to the absorber 
column, while the released CO2 may be further processed 
before compression to a supercritical state for efficient 
transportation to a storage location.
    After drying, the CO2 released from the regenerator is 
relatively pure. However, successful CO2 removal requires 
very low levels of SO2 and NO2 entering the 
CO2 absorber, as these species also react with the solvent. 
Thus, high-efficiency SO2 and NOX control systems 
are essential to minimizing solvent consumption costs for post-
combustion CO2 capture. Extensive RD&D is in progress to 
improve the solvent and system designs for power boiler applications 
and to develop better solvents with greater absorption capacity, less 
energy demand for regeneration, and greater ability to accommodate flue 
gas contaminants.
    At present, monoethanolamine (MEA) is the ``default'' solvent for 
post-combustion CO2 capture studies and small-scale field 
applications. Processes based on improved amines, such as Fluor's 
Econamine FG Plus and Mitsubishi Heavy Industries' KS-1, are under 
development. The potential for improving amine-based processes appears 
significant. For example, a recent study based on KS-1 suggests that 
its impact on net power output for a supercritical PC unit would be 19 
percent and its impact on the levelized cost-of-electricity would be 44 
percent, whereas earlier studies based on suboptimal MEA applications 
yielded output penalties approaching 30 percent and cost-of-electricity 
penalties of up to 65 percent.
    Accordingly, amine-based engineered solvents are the subject of 
numerous ongoing efforts to improve performance in power boiler post-
combustion capture applications. Along with modifications to the 
chemical properties of the sorbents, these efforts are addressing the 
physical structure of the absorber and regenerator equipment, examining 
membrane contactors and other modifications to improve gas-liquid 
contact and/or heat transfer, and optimizing thermal integration with 
steam turbine and balance-of-plant systems. Although the challenge is 
daunting, the payoff is potentially massive, as these solutions may be 
applicable not only to new plants, but to retrofits where sufficient 
plot space is available at the back end of the plant.
    Finally, as discussed earlier, deploying USC PC technology to 
increase efficiency and lower uncontrolled CO2 per MWh can 
further reduce the cost impact of post-combustion CO2 
capture.
    Chilled Ammonia Process.--Post-combustion CO2 capture 
using a chilled ammonia-based solvent offers the promise of 
dramatically reducing parasitic power losses relative to MEA. In the 
process currently under development and testing by Alstom and EPRI, 
respectively, CO2 is absorbed in a solution of ammonium 
carbonate, at low temperature and atmospheric pressure, and combines 
with the NaCO3 to form ammonium bicarbonate.
    Compared with amines, ammonium carbonate has over twice the 
CO2 absorption capacity and requires less than half the heat 
to regenerate. Further, regeneration can be performed under higher 
pressure than amines, so the released CO2 is already 
partially pressurized. Therefore, less energy is subsequently required 
for compression to a supercritical state for transportation to an 
injection location. Developers have estimated that the parasitic power 
loss from a full-scale supercritical PC plant using chilled ammonia 
CO2 capture could be as low as 10 percent, with an 
associated cost-of-electricity penalty of just 25 percent. Following 
successful experiments at 0.25 MWe scale, Alstom and a consortium of 
EPRI members are constructing a 1.7 MWe pilot unit to test the chilled 
ammonia process with a flue gas slipstream at We Energies' Pleasant 
Prairie Power Plant.
    Other ``multi-pollutant'' control system developers are also 
exploring ammonia-based processes for CO2 removal.
                      oxy-fuel combustion boilers
    Fuel combustion in a blend of oxygen and recycled flue gas rather 
than in air (known as oxy-fuel combustion or oxy-combustion) is gaining 
interest as a viable CO2 capture alternative for PC and CFB 
plants. The process is applicable to virtually all fossil-fueled boiler 
types and is a candidate for retrofits as well as new power plants.
    Firing coal with high-purity oxygen alone would result in too high 
of a flame temperature, which would increase slagging, fouling, and 
corrosion problems, so the oxygen is diluted by mixing it with a 
slipstream of recycled flue gas. As a result, the flue gas downstream 
of the recycle slipstream take-off consists primarily of CO2 
and water vapor (although it also contains small amounts of nitrogen, 
oxygen, and criteria pollutants). After the water is condensed, the 
CO2-rich gas is compressed and purified to remove 
contaminants and prepare the CO2 for transportation and 
storage.
    Oxy-combustion boilers have been studied in laboratory-scale and 
small pilot units of up to 3 MWt. Two larger pilot units, at 10 MWe, 
are now under construction by Babcock & Wilcox (B&W) and Vattenfall. An 
Australian-Japanese project team is pursuing a 30 MWe repowering 
project in Australia. These larger tests will allow verification of 
mathematical models and provide engineering data useful for designing 
pre-commercial systems. The first such pre-commercial unit could be 
built at SaskPower's Shand station near Estevan, Saskatchewan. 
SaskPower, B&W Canada, and Air Liquide have been jointly developing an 
oxy-combustion SCPC design, and a decision on whether to proceed to 
construction is expected by late 2007, with a target in-service date of 
2011-2012.
             co2 transport and geologic storage
    Application of CO2 capture technologies implies that 
there will be secure and economical storage or beneficial uses that can 
assure CO2 will be kept out of the atmosphere. Natural 
underground CO2 reservoirs in Colorado, Utah, and other 
western states testify to the effectiveness of long-term geologic 
CO2 storage. CO2 is also found in natural gas 
reservoirs, where it has resided for millions of years. Thus, evidence 
suggests that similarly ``capped'' geologic formations will be ideal 
for storing CO2 for millennia or longer.
    The most developed approach for large-scale CO2 storage 
is injection into depleted or partially depleted oil and gas reservoirs 
and similar geologically sealed ``saline formations'' (porous rocks 
filled with brine that is impractical for desalination). Partially 
depleted oil reservoirs provide the potential added benefit of enhanced 
oil recovery (EOR). [EOR is used in mature fields to recover additional 
oil after standard extraction methods have been used. When 
CO2 is injected for EOR, it causes residual oil to swell and 
become less viscous, allowing some to flow to production wells, thus 
extending the field's productive life.] By providing a commercial 
market for CO2 captured from industrial sources, EOR helps 
the economics of CCS projects, and in some cases can reduce regulatory 
and liability uncertainties. Although less developed than EOR, 
researchers are exploring the effectiveness of CO2 injection 
for enhancing production from depleted natural gas fields (particularly 
in compartmentalized formations where pressure has dropped) and from 
deep methane-bearing coal seams. DOE and the International Energy 
Agency are among the sponsors of such efforts.
    Geologic sequestration as a strategy for reducing CO2 
emissions to the atmosphere is currently being demonstrated in several 
projects around the world. Three larger-scale projects--Statoil's 
Sleipner Saline Aquifer CO2 Storage project in the North Sea 
off of Norway; the Weyburn Project in Saskatchewan, Canada; and the In 
Salah Project in Algeria--together sequester about 3-4 million metric 
tons of CO2 per year, which collectively approaches the 
output of just one typical 500 MW coal-fired power plant. With 17 
collective operating years of experience, these projects have thus far 
demonstrated that CO2 storage in deep geologic formations 
can be carried out safely and reliably. Statoil estimates that 
Norwegian greenhouse gas emissions would have risen incrementally by 3 
percent if the CO2 from the Sleipner project had been vented 
rather than sequestered.\3\
---------------------------------------------------------------------------
    \3\ http://www.co2captureandstorage.info/
project_specific.php?project_id=26.
---------------------------------------------------------------------------
    Table 2 lists a selection of current and planned CO2 
storage projects as of early 2007, including those involving EOR.

                                       TABLE 2.--SELECT EXISTING AND PLANNED CO2 STORAGE PROJECTS AS OF EARLY 2007
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                       Anticipated amount injected by
               Project                        CO2 Source                 Country                   Start          --------------------------------------
                                                                                                                       2006         2010         2015
--------------------------------------------------------------------------------------------------------------------------------------------------------
Sleipner.............................  Gas. Proc...............  Norway.................  1996...................         9 MT        13 MT        18 MT
Weyburn..............................  Coal....................  Canada.................  2000...................         5 MT        12 MT        17 MT
In Salah.............................  Gas. Proc...............  Algeria................  2004...................         2 MT         7 MT        12 MT
Snohvit..............................  Gas. Proc...............  Norway.................  2007...................  ...........         2 MT         5 MT
Gorgon...............................  Gas. Proc...............  Australia..............  2010...................  ...........  ...........        12 MT
DF-1 Miller..........................  Gas.....................  U.K....................  2009...................  ...........         1 MT         8 MT
DF-2 Carson..........................  Pet Coke................  U.S....................  2011...................  ...........  ...........        16 MT
Draugen..............................  Gas.....................  Norway.................  2012...................  ...........  ...........         7 MT
FutureGen............................  Coal....................  U.S....................  2012...................  ...........  ...........         2 MT
Monash...............................  Coal....................  Australia..............  NA.....................  ...........  ...........           NA
SaskPower............................  Coal....................  Canada.................  NA.....................  ...........  ...........           NA
Ketzin/CO2 STORE.....................  NA......................  Germany................  2007...................  ...........        50 KT        50 KT
Otway................................  Natural.................  Australia..............  2007...................  ...........       100 KT       100 KT
                                                                                                                  --------------------------------------
    TOTALS...........................  ........................  .......................  .......................        16 MT        33 MT        99 MT
--------------------------------------------------------------------------------------------------------------------------------------------------------
Source: Sally M. Benson, ``Can CO2 Capture and Storage in Deep Geological Formations Make Coal-Fired Electricity Generation Climate Friendly?''
  Presentation at Emerging Energy Technologies Summit, UC Santa Barbara, California, February 9, 2007. [Note: Statoil has subsequently suspended plans
  for the Draugen project and announced a study of CO2 capture at a gas-fired power plant at Tjeldbergodden. BP and Rio Tinto have announced the coal-
  based ``DF-3'' project in Australia.]

    Enhanced Oil Recovery.--Experience relevant to CCS comes from the 
oil industry, where CO2 injection technology and modeling of 
its subsurface behavior have a proven track record. EOR has been 
conducted successfully for 35 years in the Permian Basin fields of west 
Texas and Oklahoma. Regulatory oversight and community acceptance of 
injection operations for EOR seem well established.
    Although the purpose of EOR is not to sequester CO2 per 
se, the practice can be adapted to include CO2 storage 
opportunities. This approach is being demonstrated in the Weyburn-
Midale CO2 monitoring projects in Saskatchewan, Canada. The 
Weyburn project uses captured and dried CO2 from the Dakota 
Gasification Company's Great Plains synfuels plant near Beulah, North 
Dakota. The CO2 is transported via a 200-mile pipeline 
constructed of standard carbon steel. Over the life of the project, the 
net CO2 storage is estimated at 20 million metric tons, 
while an additional 130 million barrels of oil will be produced.
    The economic value of EOR with CCS represents an excellent 
opportunity for initial geologic sequestration projects like Weyburn. 
In addition, ``next generation'' CO2-EOR processes could 
boost technically recoverable oil resources in the United States by 160 
billion barrels, which could help offset oil imports.\4\ This also 
represents a potential demand for an additional 17.5 billion tons of 
CO2 in the EOR market.
---------------------------------------------------------------------------
    \4\ http://www.adv-res.com/pdf/Game_Changer_Document.pdf.
---------------------------------------------------------------------------
                        ccs in the united states
    A DOE-sponsored R&D program, the ``Regional Carbon Sequestration 
Partnerships,'' is engaged in mapping U.S. geologic formations suitable 
for CO2 storage. Evaluations by these Regional Partnerships 
and others suggest that enough geologic storage capacity exists in the 
United States to hold several centuries' production of CO2 
from coal-based power plants and other large point sources.
    The Regional Partnerships are also conducting pilot-scale 
CO2 injection validation tests across the country in 
differing geologic formations, including saline formations, deep 
unmineable coal seams, and older oil and gas reservoirs. Figure 11 
illustrates some of these options. These tests, as well as most 
commercial applications for long-term storage, will use CO2 
compressed for volumetric efficiency to a liquid-like ``supercritical'' 
state; thus, virtually all CO2 storage will take place in 
formations at least a half-mile deep, where the risk of leakage to 
shallower groundwater aquifers or to the surface is less likely to 
occur. 

[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]

    After successful completion of pilot-scale CO2 storage 
validation tests, the Partnerships will undertake large-volume storage 
tests, injecting quantities of 1 million metric tons of CO2 
or more over a several year period, along with post-injection 
monitoring to track the absorption of the CO2 in the target 
formation(s) and to check for potential leakage.
    The EPRI-CURC Roadmap identifies the need for several large-scale 
integrated demonstrations of CO2 capture and storage. This 
assessment was echoed by MIT in its recent Future of Coal report, which 
calls for 3 to 5 U.S. demonstrations of about 1 million metric tons of 
CO2 per year and about 10 worldwide.\5\ These demonstrations 
could be the critical path item in commercialization of CCS technology. 
In addition, EPRI has identified 10 key topics where further technical 
and/or policy development is needed before CCS can become fully 
commercial:
---------------------------------------------------------------------------
    \5\ http://web.mit.edu/coal/The_Future_of_Coal.pdf.
---------------------------------------------------------------------------
  --Caprock integrity;
  --Injectivity and storage capacity;
  --CO2 trapping mechanisms;
  --CO2 leakage and permanence;
  --CO2 and mineral interactions;
  --Reliable, low-cost monitoring systems;
  --Quick response and mitigation and remediation procedures;
  --Protection of potable water;
  --Mineral rights; and
  --Long-term liability.
    Figure 12 summarizes the relationship between EPRI's recommended 
large-scale integrated CO2 capture and storage 
demonstrations and the Regional Partnerships' ``Phase III'' large-
volume CO2 storage tests.

[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]

                     co2 transportation
    Mapping of the distribution of potentially suitable CO2 
storage formations across the country, as part of the research by the 
Regional Partnerships, shows that some areas have ample storage 
capacity while others appear to have little or none. Thus, implementing 
CO2 capture at some power plants may require pipeline 
transportation for several hundred miles to suitable injection 
locations, possibly in other states. Although this adds cost, it does 
not represent a technical hurdle because long-distance, interstate 
CO2 pipelines have been used commercially in oilfield EOR 
applications. Nonetheless, EPRI expects that early commercial CCS 
projects will take place at coal-based power plants near sequestration 
sites or an existing CO2 pipeline. As the number of projects 
increases, regional CO2 pipeline networks connecting 
multiple industrial sources and storage sites will be needed.
         policy-related long-term co2 storage issues
    Beyond developing the technological aspects of CCS, public policy 
needs to address issues such as CO2 storage site permitting, 
long-term monitoring requirements, and liability. CCS represents an 
emerging industry, and the jurisdiction for regulating it has yet to be 
determined.
    Currently, efforts are under way in some States to establish 
regulatory frameworks for long-term geologic CO2 storage. 
Additionally, stakeholder organizations such as the Interstate Oil and 
Gas Compact Commission (IOGCC) are developing their own suggested 
regulatory recommendations for States drafting legislation and 
regulatory procedures for CO2 injection and storage 
operations.\6\ Other stakeholders, such as environmental groups, are 
also offering policy recommendations. EPRI expects this field to become 
very active soon.
---------------------------------------------------------------------------
    \6\ http://www.iogcc.state.ok.us/PDFS/
CarbonCaptureandStorageReportandSummary.pdf.
---------------------------------------------------------------------------
    Because some promising sequestration formations underlie multiple 
States, a State-by-State approach may not be adequate. At the Federal 
level, the U.S. EPA published a first-of-its-kind guidance (UICPG No. 
83) on March 1, 2007, for permitting underground injection of 
CO2.\7\ This guidance offers flexibility for pilot projects 
evaluating the practice of CCS, while leaving unresolved the 
requirements that could apply to future large-scale CCS projects.
---------------------------------------------------------------------------
    \7\ http://www.epa.gov/safewater/uic/pdfs/
guide_uic_carbonsequestration_final-03-07.pdf
---------------------------------------------------------------------------
           long-term co2 storage liability issues
    Long-term liability of storage sites will need to be assigned 
before CCS can become fully commercial. Because CCS activities will be 
undertaken to serve the public good, as determined by government 
policy, and will be implemented in response to anticipated or actual 
government-imposed limits on CO2 emissions, a number of 
policy analysts have suggested that the entities performing these 
activities should be granted a large measure of long-term risk 
reduction.
         rd&d investment for advanced coal and ccs technologies
    Developing the suite of technologies needed to achieve competitive 
advanced coal and CCS technologies will require a sustained major 
investment in RD&D. As shown in Table 3, EPRI has estimated that an 
expenditure of approximately $8 billion will be required in the 10-year 
period from 2008-2017. The MIT Future of Coal report estimates the 
funding need at up to $800-$850 million per year, which approaches the 
EPRI value. Further, EPRI expects that an RD&D investment of roughly 
$17 billion will be required over the next 25 years.
    Investment in earlier years may be weighted toward IGCC, as this 
technology is less developed and will require more RD&D investment to 
reach the desired level of commercial viability. As interim progress 
and future needs cannot be adequately forecast at this time, the years 
after 2023 do not distinguish between IGCC and PC.

          TABLE 3.--RD&D FUNDING NEEDS FOR ADVANCED COAL POWER GENERATION TECHNOLOGIES WITH CO2 CAPTURE
----------------------------------------------------------------------------------------------------------------
                                      2008-12         2013-17         2018-22         2023-27         2028-32
----------------------------------------------------------------------------------------------------------------
Total Estimated RD&D Funding            $830M/yr        $800M/yr        $800M/yr        $620M/yr        $400M/yr
 Needs (Public + Private
 Sectors).......................
Advanced Combustion, CO2 Cap-         25 percent      25 percent      40 percent      80 percent      80 percent
 ture...........................
Integrated Gasification Combined      50 percent      50 percent      40 percent      80 percent      80 percent
 Cycle (IGCC), CO2 Capture......
CO2 Storage.....................      25 percent      25 percent      20 percent      20 percent      20 percent
----------------------------------------------------------------------------------------------------------------

    By any measure, these estimated RD&D investments are substantial. 
EPRI and the members of the CoalFleet for Tomorrow program, by 
promoting collaborative ventures among industry stakeholders and 
governments, believe that the costs of developing critical-path 
technologies for advanced coal and CCS can be shouldered by multiple 
participants. EPRI believes that government policy and incentives will 
also play a key role in fostering CCS technologies through early RD&D 
stages to achieve widespread, economically feasible deployment capable 
of achieving major reductions in U.S. CO2 emissions.

    Senator Dorgan. Mr. Phillips, thank you very much.
    Let me read some information--some of you may know this--
from a Department of Energy report. It says: ``The Williston 
Basin oil [and gas] producing region of North Dakota, South 
Dakota and Montana has an original oil endowment of about 13 
billion barrels,'' according to the Department of Energy. Of 
this, they say 4 billion barrels, about 29 percent, will be 
recovered with primary and secondary oil recovery techniques. 
But that means 9 billion barrels of oil that they estimate 
exists will be left in the ground or stranded if they simply 
follow the use of traditional oil recovery practices.
    The report also says that a major portion of this stranded 
oil is in reservoirs technically and economically amenable to 
enhanced oil recovery using carbon dioxide injection. Now, it 
says, that the 13 billion barrels of oil in place for the 
Williston Basin includes only a modest portion of the larger 
unconventional oil resource that might be in the Bakken shale. 
As I indicated earlier, I had the U.S. Geological Survey here 
in North Dakota. They are redoing the Bakken shale report in, I 
think, the first quarter of 2008. I would have to go back and 
check on the date. As soon as we get that, we will have more 
information about what the potentially recoverable resources 
are in the Bakken shale.
    But it seems to me like there is a significant opportunity, 
even as we talk now, in additional coal resources being used in 
plants that will produce CO2 if we have beneficial 
use of CO2 and then can enhance oil recovery in the 
same region. It seems to me like it's a win on both counts. The 
question is, first of all, how much of that is just theory and 
how much of it will be achievable given the economics of all of 
this? How does one construct the framework for it, the 
infrastructure to make it happen?
    Mr. Harper, let me ask you the first question. You've been 
doing some real world work in this capturing and moving 
CO2, actually selling it in a pipeline. What has 
Basin Electric learned in partnering with the oil companies to 
capture, move and use CO2 for beneficial use? What 
have you learned?
    Mr. Harper. Well, the first thing we've learned is doing it 
is not necessarily the easiest thing in the world. I recall 
when we first turned the valve in 2000, we learned, as did the 
oil company that they had not successfully prepared their field 
for the CO2 to be injected in there. Therefore, 
there were leaks of the gas. But those have since been fixed. 
That particular field today, as I understand it, is--it was 
producing about 10,000 barrels of oil a day. It's now producing 
over 30. So it's proving out the technology. In fact, I spent 
last Wednesday and Thursday in the gas plant, as well as up in 
the Weyburn and Midale fields visiting with customers up there 
trying to learn more, and what I found is their long-term goal 
is to capture upwards of 50 percent of the oil out of that 
field, and that's where they think it will plateau with this 
current technology. As was said earlier, the oil companies are 
desirous of as much CO2 as we can provide them 
because they see it as a true benefit.
    What I also found is that both oil companies are doing 
different technologies with respect to how they put it into the 
oilfield, they recycle the existing CO2. And so it 
was quite interesting to see again how they're applying the 
different technologies, which to me is showing that technology 
will advance as to where we need to be in successfully 
capturing CO2 and using it for an incentive for oil 
production, but, more importantly, to again continue our long-
term viability of utilizing fossil fuels. So it's been a 
tremendous learning curve for us.
    As you mentioned earlier, we currently capture about 49 
percent of the CO2. As we look at pieces of 
legislation, one of the recent ones was a 70 percent capture 
level, so I asked our engineers at the plant, what would it 
take for us economically to go from 49 percent to 70 percent? 
They came back and said it would cost us another $165 million 
plus another $40 million annually in operating costs. Again, 
those are huge numbers, but I think, again, as we move our way 
through the technology developments, and so on, those costs 
will come down. That's just some of the lessons that we're 
learning.
    Senator Dorgan. All right. One quick question, the 
CO2 goes north to the Alberta oilfields, any reason 
that they were the earlier market as opposed to the oilfields 
in North Dakota or Montana?
    Mr. Harper. A lot of the work was done prior to me coming 
here, but I've since learned through additional discussions 
that the problem was the pricing of the CO2 and the 
fact that some of the old companies couldn't come together with 
the economics to make it work, whereas, on the other side, 
quite frankly, the Canadian government provided them with an 
incentive to develop those fields, and so that lent itself to 
more economic advantage for that customer up there.
    Senator Dorgan. So, in addition, it was a public policy 
initiative?
    Mr. Harper. Absolutely.
    Senator Dorgan. Mr. Weeda, you've described in some detail 
your project, which is, I think, an exciting, interesting and 
very large project. I believe it could be something that's 
significant for our region and something, I think, that our 
country could learn from. We're trying a lot of different 
applications and models around the country to try to understand 
what kinds of capabilities we have with various sources of 
energy. What kinds of challenges do you see, at this point, for 
the project? What do you need to understand from policymakers 
for the purposes of this project and its future?
    Mr. Weeda. When we're looking at the American Lignite 
Energy project, it's certainly a large project, we'll need 
financial backing. We're focusing on using technologies that 
are commercially available that we would be able to get 
performance guarantees on so the bankers would be willing to 
support the project. And to that extent the public policy that 
would help assure us that the fluctuation on oil prices, there 
perhaps could be a policy that would help us face that 
potential in the event that oil prices went down.
    I think incentives for the development, the industry as a 
whole. We're being careful to try to develop products that 
would fit into the existing infrastructure and not have to 
develop a new retailing market, but to be able to get those 
products into the market, the public policy that would support 
that, as well. In addition, the CO2 sequestration 
portion of it. The CO2 is separated in the process. 
We are also looking at enhanced oil recovery. But as was 
mentioned, the regulatory framework and the liabilities 
associated with utilization of CO2 are definitely an 
important public policy aspect.
    Senator Dorgan. Are you optimistic about the future with 
respect to CO2 sequestration, even though, as you 
know, much of it's still in the demonstration stage?
    Mr. Weeda. As we heard from EPRI, similar timeframes of 
what I have heard about when the technology will be mature 
enough to go to the bank and be able to finance a project, but 
we are working closely with EPRI and others on helping develop 
those opportunities. As I mentioned, we have a goal within our 
company of reducing our CO2 footprint so we're very 
anxious, but we don't see any single technology that's going to 
get us there, and that's why I mentioned so many projects 
today, because we're looking at the small increments of 
CO2 we can get in each one. One thing I didn't 
really mention here is the ethanol industry has a 
CO2 stream which could be sequestered. We, of 
course, with other interests here, at Blue Flint and with the 
coming interests at Spiritwood, would like to see opportunities 
to sequester that CO2, as well.
    Senator Dorgan. Mr. Nelson, Mr. Harper talked about how 
public policy in Canada was helpful to that oilfield seeking to 
engage in the purchase of CO2.
    You seemed in your statement to be fairly enthusiastic 
about the opportunities here for enhanced oil recovery using 
CO2. What kind of public policy initiatives are 
required, do you think, to move forward, if any?
    Mr. Nelson. I do think, first off, just the regulatory and 
legal framework that allows you to understand who has the 
liability, what is the permitting requirements, what monitoring 
requirements are there, et cetera, and that's fairly well 
detailed in the NPC report. In fact, we worked with your 
committee on that. That's one.
    I think the other one is, and was mentioned a little bit, 
in terms of using it in EOR, today there are no requirements to 
sequester the CO2 in EOR projects. It's mainly to 
circulate. There's no requirement to actually sequester the 
CO2 ultimately. So that's something that should 
probably be looked at. The other thing that I think was sort of 
alluded to, and that is that today, in fact, most of the 
CO2 that's used in the EOR projects is actually 
CO2 that we produced purposely from the ground, 
where we had it sequestered nicely and taken it out and now are 
circulating it, so it's a little bit counterintuitive, if you 
want to reduce CO2, you take the CO2 
that's been sequestered geologically out of the ground and 
circulate it. So I think there is scope to look at some 
incentives to ensure that we are using anthropogenic 
CO2 for EOR purposes.
    Senator Dorgan. We had invited some local oil interests to 
testify. They preferred that you speak on their behalf. But is 
the industry, itself, excited about this, anxious to move 
toward it, or is it just something that exists that they will 
take advantage of when it is possible to take advantage of it?
    Mr. Nelson. Well, I think it's all driven--I think there 
are two factors. One is that this is not a new concept. The 
concept of using CO2 or other substances to enhance 
oil production has been around for a long time. That's one. So 
I don't know that anybody's--a light bulb has gone off in 
anybody's head because they've known about it. The economics 
haven't been there.
    Second, and Carl alluded to this a little bit, is a lot of 
the older fields in the United States now are in the hands of 
independent oil and gas producers, not major oil companies that 
have big research labs. So I think there is clearly scope to 
improve our understanding of what happens in the reservoir. 
That will have to be led by the DOE, and service companies like 
ours, to get it applied in the field, because most of the oil 
and gas producers don't have the capability to do it 
themselves, in the lower 48.
    Senator Dorgan. I should mention to you, as you know, the 
President zeroed out oil and gas research in his budget 
request.
    Mr. Nelson. I know that.
    Senator Dorgan. I added money back in, because I don't 
think that makes a lot of sense. I understand that perhaps some 
of the majors have some money do some research, but most of the 
independents do not and, if we're going to try to solve these 
problems, we have to continue to engage in oil and gas 
research. That may be counterintuitive for some, but I think 
that since we're going to use fossil fuel, let's try to 
evaluate through research, both privately funded and publicly 
funded, how we do it and develop that base of knowledge.
    Mr. Nelson. That's exactly right.
    Senator Dorgan. Mr. Phillips, you, as you indicated, 
testified previously at the Energy Committee. Let's talk about 
your work. Some people have said to me that there are other 
beneficial uses of coal, including lignite coal, coal to 
plastics, obviously coal to synthetic gas, and so on, coal to 
liquids. You have an array of potential uses. What's your 
assessment of those potential uses of lignite for North Dakota? 
What is most advantageous?
    Mr. Phillips. Well, we have looked at coal to liquids for 
transportation fuels, as well as substitute natural gas as 
they're doing at Great Plains. One of the things that we see 
is, particularly for coal to liquids, you need such large-scale 
volumes to make it competitive. You basically build a large 
coal gasification complex like they have at Great Plains plus a 
large oil refinery, and that costs billions of dollars, and, 
frankly, there just aren't that many organizations in the 
world, much less the United States, able to do those sorts of 
things. So as GRE was pointing out, there's going to have to be 
some sort of financial risk mitigation in order to induce 
various banks to come in and say, okay, we'll put in our share 
of that several billion dollars. That's why you're not seeing 
it. Even though oil prices are at a level where these types of 
things should be competitive, you're not seeing a bunch of them 
being built simply because it's such a huge hurdle to come up 
with that kind of money. And, again, no one knows exactly what 
oil prices will be in the future. So that's the other reason 
why there's some hesitancy. If oil companies thought that oil 
prices were going to stay up, they would start building right 
away.
    Senator Dorgan. Mr. Weeda, you raised the question of the 
size, the scale of the projects of this type. I assume that's 
an accurate reflection of what's necessary. You can't do 
commercially viable small projects when you're dealing with 
this, can you?
    Mr. Weeda. That's correct. We have also found in our 
studies of this facility that we did need to scale up to the 
current size to make it more economical and, yes, indeed, it's 
a major investment and certainly going to take a lot of help to 
get this into a full-scale project. We are in the middle of 
what we call the pre-feed study, but the next increment is to 
go to the full feed study, which is about a $50 million 
investment.
    Senator Dorgan. I'll ask Mr. Harper, you know, we're 
dealing with this issue of carbon capture now, as part of the 
climate change calculation. Later we're going to go to 
conference dealing with energy policy between the House and the 
Senate. I suspect that will begin in September; it will take a 
while. But, you know, one of the considerations there will be 
the issue of carbon capture. There will be a climate change 
bill, I expect, at some point in this Congress that will begin 
moving. We don't know the ingredients to that. Right now we 
need to ask, how do we capture carbon? How do we capture it and 
sequester it? How do we capture and use it? What are your 
thoughts about what is achievable generally speaking? Because 
you've captured and used it for beneficial purposes. Some say 
``We understand you're going to require carbon capture, but if 
you require carbon capture at 95 or 98 percent, well at this 
point we don't see that technology or we don't have that 
capability and you're just simply shutting down the projects.'' 
Give me your assessment of where we are on this discussion 
about carbon capture.
    Mr. Harper. First understand I'm not an electrical engineer 
or chemist, but as I listen to my people at the gas plant, my 
people on the electric generation side, we're talking to major 
companies, General Electric, Mitsubishi, on and on and on. In 
fact, when I was at the plant last Wednesday, Mitsubishi 
happened to be there and we met and discussed it. There are so 
many little nuances that have to be looked at in technology. 
For instance, the cleanliness of a sulfur strain can impact how 
the capture of carbon takes place. So as we look at 
technologies, my engineers are telling me that if you don't 
have a very clean sulfur strain, you may have to put on 
additional technologies to clean it up before it ever goes to 
the carbon capture process--a major challenge.
    But some of the things that were spoken of earlier in 
Carl's testimony that, I think, plays a large part in this is 
the public awareness. You know, one of the things I learned by 
attending an IEA workshop earlier this year was that we can 
talk about all the technologies, and we will reach some level 
of technology success in my mind--we will, we have to--but 
people do not today understand what really is going on here 
with respect to carbon capture and storage process. They hear 
it a lot on TV, they hear it in movies, they read it in 
magazines, but the fact of the matter is the everyday person 
out there, in my mind, does not understand really what's going 
on here, because if you look at the costs associated with all 
of this--you heard the 18th plant down the road is going to be 
cheaper obviously than the first one. What's that really going 
to do to our cost of electricity and cost of energy for this 
country's growing economy, for this world's growing economy?
    I guess my concern is that while we will ultimately develop 
those technologies, we've got to work on public awareness, we 
have to work on regulatory framework, we have to work on the 
legal aspects of this thing and set the road map for us to move 
forward, because if we don't, I think we're going to fail with 
respect to our economy, and I'm concerned about that.
    Now, having said all of that, you heard Carl talk about 
2020, 2025. EPRI and all their studies focused on that 2025 
timeframe as well. Everybody has a belief today that the IGCC 
type of technology and carbon capture is already here, they're 
working, and that's not the reality. The fact of the matter is 
all of these are in small-scale types of testing going on, and 
that's what we're trying to prove at Basin Electric at our 
Antelope Valley Station project, but they're not there yet. We 
cannot simply stop this economy from growing and say time out 
until we get the technology to catch up. We have to have in my 
mind legislation that allows time for these things to develop, 
incentives for these things to develop; otherwise, we're not 
going to be successful.
    Senator Dorgan. Mr. Nelson, I mentioned to you that the 
President zeroed out the research for oil and gas, I put the 
money back in. What will that research money be used for? What 
will be beneficial in terms of these issues, particularly in 
the area of using enhanced oil recovery techniques using 
CO2?
    Mr. Nelson. I think that there's a lot of work still to do, 
and understand every reservoir is different, so it's not like a 
plant on the surface where you can build them in cookie-cutter 
style. So it's important that we understand the differences and 
nuances, what really happens chemically and physically downhole 
when we start injecting CO2. There's also the study 
you quoted that had these billions of barrels of technically 
recoverable oil. Part of that was in what's called transition 
zones, where we're talking about areas where traditionally the 
oil has not flowed, it's high, it's trapped in very tiny pore 
spaces, so to get that to flow, there's a lot of work to 
understand whether that really is feasible or whether it's not, 
quite honestly.
    But I think the other part of it is, and we touched on it 
earlier, a lot of it ought to go towards demonstration projects 
which help the independent oil and gas producers in the United 
States, particularly the lower 48 of the United States, on 
land, to help them implement these technologies in projects 
that can start to have an impact. So a lot of it is going 
toward demonstration projects to help those independents.
    Senator Dorgan. Let me ask Carl and Jeffrey, as well. Many 
of these projects--John Weeda's project, for example, have 
fairly long lead times, but we're in a period here in this 
country where policy change is happening. I mean, you can just 
see what's happening in this country. All of a sudden energy 
and climate change are fused as part of the consideration of 
what we do in the future. And so because you have long lead 
times and large projects, and because we will not go from zero 
to 60 with a new standard immediately, how do we create a 
bridge for the certainty that's needed for investors? We're not 
going to get projects built, we're not going to get projects 
built to demonstrate or to prove what different kinds of 
technologies can offer us if we don't tell those who want to 
build them: ``Here's a transition from here to there.'' I'm not 
sure I've asked that question very well here.
    Let's assume that we're going to get to a point where we 
require coal to liquids, we get to a point where we require a 
certain standard of carbon capture, but we're not going to go 
from here to there within the next 30 days; right? That's not 
the way you do that. So how do you create the transitional 
bridge here so that we can continue to get projects built that 
give us the knowledge and the demonstration of technology that 
we need as we proceed?
    Carl?
    Mr. Bauer. I think that's an excellent question. You know, 
we're asking the industry to fly and they're not even running 
on this particular issue. They're studying it; they're walking, 
if you will, through the process. They're making investment out 
of their own bottom line basically because this whole thing is 
not required as of yet, so pretty much the R&D has to come off 
the bottom line so that they at least understand and be able to 
converse on this as they are. So I'm thinking that, recognizing 
that point, we need to pick more realistic in-between points 
that we would like to stimulate them getting to. I think if we 
look at what's been done over the past decade or two for wind, 
how we knew we needed to do something about making wind energy 
a more economically viable contributor to the energy picture.
    Well, if we recognize--and I think what we suffer from in 
the use of coal fuel largely is that, because it's been there a 
long time, it's assumed it can do whatever it has to do or it 
won't play, like we can afford it not to play. Well, reality is 
we cannot afford not to play. To replace half the electricity 
generation in this country, there is not sufficient financial 
capital to do that in 3 decades, quite frankly, without having 
tremendous damage to the country.
    So then how do we move and deal with the other big issue, 
which is how do we get the greenhouse gas down? And I think 
ways to share--if you go back to the question about why Weyburn 
instead of the southwestern part of North Dakota, the Canadian 
Government put up money to put the pipeline in place, there was 
a small contribution of that from the Federal Government of the 
United States through DOE's sequestration program, because we 
want to understand the handling and the injection and how that 
plays, but I think the projects that have the potential to 
utilize CO2 but cannot financially get there because 
of economics or if you go to coal to liquids, it's a good idea 
to address these other issues, how do we deal with the 
CO2 portion of it seems to be the biggest hurdle 
right now, find a way for the financial support, whether it's 
loan guarantees, tax credits and R&D. I think those three 
forces have to come together to stimulate the same way that the 
ethanol continues to benefit from some help in making it a 
market-viable product. Those things all have to go forward.
    Now, one of the things, I think--and you know better than 
I, Senator--the discussion becomes why that fuel versus my 
fuel. The reality is we need them all. We just do not have a 
one-trick pony. We have got to have in this country a viable 
diversity of portfolio to meet the demand. I think if we really 
look at it that way, we take a similar approach that we've done 
on some of the renewables with coal/liquids and with moving at 
least CO2 towards EOR and defray some of the costs 
of getting it into a viable position to be for the next decade, 
mainly of EOR as it moves forward.
    Having said that, I do think the plants that get built have 
a 30-to 40-year life cycle, so one has to say those plants have 
to recognize that they are going to have another level of 
performance required eventually in 20 years. And how they begin 
to set themselves up for that should be part of their initial 
design process.
    Senator Dorgan. Thank you. Jeffrey.
    Mr. Phillips. Yes. You said earlier that Congress was going 
to have to make decisions on climate change policy, and all I 
can say is better you than me. It's an enormous responsibility 
and will have significant impacts on our economy obviously.
    But in terms of how we could make that transition or that 
bridge, what we've tried to do in our R&D augmentation study is 
to point bite-size projects that need to happen in a timeline, 
with the assumption that 2020 is the time that we need to have 
full-scale technology proven. And I'll give you just one 
example of what we're proposing. We're going to take somebody 
out there who wants to build a new coal plant and say, okay, 
build that new coal plant with the money that you said you were 
going to use, and then we will put together a coalition of 
other companies and perhaps the Federal Government, also, to 
pay for the cost of adding CO2 capture to a portion 
of your powerplant. Maybe it's only 50 percent. Then we will 
take that CO2 and if we can sell it for EOR, it will 
help cover the costs of compressing it, and if we can't, then 
we're going to have additional incentives to cover the cost for 
sticking it into the ground. That would be something that we 
could do--we believe we can get a plant like that going by the 
2012 timeframe. If you let that run for 4 or 5 years, you're 
going to show people that this technology exists such that we 
would then be in a position where we could then go forward with 
a plant that was full-scale, a 100 percent--or not a 100 
percent capture, but getting as much CO2 as we felt 
was needed.
    So that's the kind of projects that we're working on. We 
certainly could use the Federal Government's assistance, 
whether it's tax incentives or direct funds. We're a 501(c)(3), 
so I can't push too hard, but obviously any help we can get 
would be great.
    Senator Dorgan. You can't push at all.
    I'm going to ask Franz if he has any questions. I want to 
mention to you, because you're talking about the research 
that's needed, that in my subcommittee--as I mentioned, Senator 
Domenici is the ranking member, he was previously the chairman 
of this subcommittee--we increased funding for coal, oil and 
gas R&D. We increased it by 30 percent above the President's 
budget request with $88 million for the Clean Coal Power 
Initiative, $374 million for coal research and development 
funding and $30 million for oil and gas research. Within the 
coal funding account we've put in $132 million for carbon 
sequestration research, $34 million for innovations for 
existing plants programs.
    The reason I did this is because it's one thing to talk 
about all of these issues and say we have to use all of our 
resources, but if you don't fund it, it's just talk. And I can 
tell you, whether it's education or a whole range of areas, 
there's a lot of talk and a lot of sloganeering and precious 
little real investment that's going to make a big difference. 
If we're going to do this, we've got to invest in research; 
we've got to invest in the demonstration projects. We just have 
to do that. And I think Senator Domenici agrees with this. We 
have a subcommittee that is very interested in changing the 
priorities of the President's budget and substantially 
increasing these investment funds.
    Franz?
    Mr. Wuerfmannsdobler. If I might, let me just ask one quick 
question in terms of how the Senator described a bridge or 
synergy approach. What is it that government can do, whether 
it's on the Federal level or a State level, to help get the 
utilities, the coal, oil, gas, chemical, pipeline and other 
industries, to start talking to each other more? Most people 
are saying, yes, we've got to do this. What is it that the 
government can do in terms of making that happen?
    Mr. Harper. Trying to get us all to talk together. Good 
question. I think we are. As I travel around, I think the 
utilities are talking to each other. We're talking to the oil 
companies. We're talking to the developers, the vendors, trying 
to find out what we can do to effectively change, find 
solutions to the challenges that we have.
    But, you know, I think the bigger issue again is the 
funding aspects, but I think even more than that is we don't 
have targets to shoot at. They're all around the board. You 
know, if we could as an industry have targets, we've proven 
that we can meet them, we roll up our sleeves, work together to 
develop the technologies. But without targets and incentives to 
get to those targets we don't have anything to shoot at. So if 
we could have something--and I'll just throw out something here 
on the table. If we could have something that says by 2020 we 
will have x in place that will move us to that continued 
ability to burn fossil fuels. Now, that x is, you know, use 
some of the recent legislation, 70 percent capture technology 
available to go in. I'm not saying it would be on board and 
working at that time, because it takes a while. I was 
interested in the 2012 timeframe of the plant being on line. I 
would like to understand how he's doing that because we're 10 
years getting a plant into production. Right, John?
    Mr. Weeda. Yes.
    Mr. Harper. But that's my viewpoint, is I think we are 
talking, I think we're all interested in finding the ways in 
which to move us forward, but if we had reasonable targets, 
achievable targets, I think we have then something to shoot at 
along with investment opportunities in research and 
development, et cetera, et cetera.
    I do applaud you, Senator, for putting those dollars back 
in there because you're absolutely right, the energy bill was 
put forth, but no appropriations were ever made, and that's a 
challenge.
    Senator Dorgan. Anybody else want to comment?
    Mr. Weeda. I would like to comment. Great River Energy 
believes a good environmental performance is good business, and 
when public policy can merge those two together, it makes a 
huge difference. One example I can point to is that because of 
the SO2 Cap and Trade Program, Great River Energy 
took initiative to improve the scrubbing capability in our 
units, and as a result we're able to offset those costs in the 
marketplace because we could do it more economically than some 
other locations. So we would certainly be interested in a 
program that helped us put CO2 in that environment, 
as well.
    I would also like to point out that none of our power 
stations perform today environmentally like they did on day 
one. We have continued to make improvements, and sometimes it's 
through those kinds of incentives--the Department of Energy 
helping us commercialize the coal-drying technology was another 
great piece in ability to move forward. The support of the 
ethanol industry has made it possible for us to partner with 
the ethanol industry with combined heat and power applications. 
So I think there are a variety of things that public policy can 
help us do, and looking at some of those past models will 
certainly help.
    Senator Dorgan. Mr. Nelson.
    Mr. Nelson. I was just going to echo what's already been 
said. I do think there is a lot of improvement in terms of 
dialog between the oil and gas industry and coal industry, et 
cetera. But I do think it happens quite naturally once we 
understand where we have to be by 2020 or 2030, we have 
targets, and the technology will get developed.
    I again applaud you for putting money back in, but I think 
you also have to keep it in perspective in terms of oil and 
gas, anyway, research. The oil and gas industry will spend 
about $6 billion this year, so what you want to do is actually 
leverage that money and make sure it does get applied in 
projects that will impact the United States, and I think 
there's ways to do that.
    Mr. Phillips. I would just like to make a couple of 
comments on a couple things that could be done. First of all, 
we need to make it clear that early movers are not going to be 
inadvertently penalized for capturing CO2 and 
putting it into enhanced oil recovery, because, for instance, 
we end up giving out credits based on your current 
CO2 emissions and they don't get credit for the 
CO2 they're already capturing and putting in the 
ground, they get penalized, versus somebody that didn't do 
that.
    The second thing that needs to be done is we need some type 
of guidelines on purity of the CO2 that can go into 
bulk pipelines, because what we're seeing is a vast array of 
specifications. The one that Great Plains uses has 1 percent 
H2S in it, which is 10,000 parts per million. A FutureGen 
project is looking at using a CO2 pipeline down in 
Texas that uses CO2 of natural sources--underground 
sources. They're saying you can't put it in unless you have 
less than 10 parts per million. So we've got 10,000 parts per 
million in one part of the country, 10 in another. Which one am 
I supposed to design for? I'll tell you what, the 10 down in 
Texas is a lot more expensive to design to, and to me it's 
almost bordering on anticompetitive behavior.
    Senator Dorgan. Thank you very much. I did want to mention 
that Ross Keys was here previously with Congressman Pomeroy's 
staff. I think he had to leave. I did not introduce Nate Hill, 
who works with me and Franz on energy issues, as well.
    I want to make just a couple of comments as we conclude 
today. First of all, there are national interests that are 
significant here. You know, we did EPACT a couple of years ago. 
We've now done another energy bill complementary to the Energy 
and Policy Act of 2 years ago. We got another energy bill 
through the Energy and Commerce Committee on which I serve. The 
House has done its energy bill and it is very different. It 
appears to me that in addition to trying to conference an 
energy bill between the House and the Senate, there will be 
climate change legislation moving at some point in this 
Congress which has a relationship to, but is separate from, 
some of these considerations.
    So what I'm hearing is the industry needs some certainty, 
they need some decisions made in order to proceed, also so that 
investors have the confidence to proceed. We're all in a 
situation where we know a lot less about these subjects than we 
think we know. We have things being done in the research 
laboratory that give us certain indications, but until you 
demonstrate them on a commercial scale, until you demonstrate 
them out there in the real world, you don't know the 
circumstances or the conditions that might exist.
    So this is a very important and a very interesting time. My 
interest in it is for a couple of reasons. First of all, as a 
member of the Energy Committee, I well understand the danger 
that exists with respect to our dependence on foreign energy. 
If we think this is just fine, to have to worry about whether 
the Saudi pipeline is going to be open to us forever, then 
we're not thinking very much. I'm not talking just about the 
Saudis. I'm talking about all oil suppliers in troubled parts 
of the world. I think finally that our country is awakening to 
how unbelievably vulnerable we are to supplies of oil that come 
from parts of the world over which we have virtually no 
control. Very few people are focusing on the fact that a 
substantial portion of the oil is controlled by foreign 
governments. And if one really wants to get a migraine, go take 
a look at what the Chinese Government is doing at this point, 
and has been doing for some while, to capture supplies of 
energy for the long term for their own needs and then evaluate 
what that means in supply/demand relationship and prices for 
our country with our prodigious energy appetite.
    Having said all of that, I also have a parochial interest 
because I live in a great State and we have unbelievable 
opportunities to produce energy--a lot of energy. As you all 
know, I'm a big fan of wind energy, I think I held five wind 
energy conferences over the years, and we now have a lot of 
wind energy development going on, but I understand that 
development turned off and on like a light switch because the 
production tax credit, which the Federal Government just 
stopped and started and stuttered on, would be turned off and 
on, off and on, every 2 years, 3 years, 1 year. So, I 
understand the influence of public policy incentives, in this 
case tax incentives, on all of these projects.
    Even as North Dakota sees more biofuels, more ethanol 
plants, more wind turbines and more wind farms being developed, 
I'm especially interested in seeing that we have an opportunity 
to continue to use our lignite coal and enhance the use of oil 
and gas production. With respect to lignite, I believe, and I'm 
going to continue to push, we can do even more in future years. 
As I chair this subcommittee, I'm going to push for 
substantially more research and development so that we can get 
to the point where we can produce our coal in these plants with 
virtually zero emissions into the atmosphere. I believe that's 
possible. Our country should aspire to achieve that.
    And, second, I also believe that, concerning the kind of 
plants you're talking about, Mr. Weeda, if we don't find a way 
to bridge from here to there the opportunity to build 
demonstration plants for commercial scale, commercial size 
demonstration plants, then we will have missed something very 
significant. We're going to be behind the curve rather than in 
front of the curve. When I say ``demonstration,'' I'm not 
suggesting a plant that's worth billions of dollars as just a 
demonstration plant, but is also a plant that will demonstrate 
to us on a commercial scale what capabilities exist in a wide 
range of technologies. If we don't understand that, don't learn 
that through the commercial demonstration of these projects, 
this country will fall behind rather than move ahead. So I'm 
very interested in trying to figure out how we bridge from here 
to there, and I'm a supporter of that effort.
    We are going to require carbon capture and we're going to 
push. I don't think we're going to loaf around as a country 
saying, yeah, do what you can, God bless you. I just had one of 
my colleagues offer an amendment like that and it was defeated 
pretty handily. That's not enough. We're going to set targets; 
we're going to reach those targets. That's the way we've always 
been. We're innovative and aggressive. But even in setting 
those targets, we've got to find ways to understand that the 
time frame here is short to some, but long to others. If we're 
talking about 5, 10 and 20 years, which is the kind of 
timeframes most of us are talking about, we need to have a path 
in those timeframes to have opportunities to build things. So 
that's why I appreciate your testimony, Mr. Weeda, because I 
think you raised those questions. And I don't know how quickly 
we can answer them, but we've got to get about the business of 
addressing them.
    I think the testimony by all of you was really helpful and 
will be a contribution to the knowledge of our committee and 
the U.S. Senate. And, Mr. Bauer, a continuing thank you to you 
for your work at the National Energy Technology Laboratory, as 
well as for your counsel to our committee.

                     ADDITIONAL SUBMITTED STATEMENT

    In addition, I would like to include in the record the 
statement of Dr. Gerald H. Groenewold, Director, Energy & 
Environmental Research Center, University of North Dakota.
    [The statement follows:]
  Prepared Statement of Dr. Gerald H. Groenewold, Director, Energy & 
       Environmental Research Center, University of North Dakota
    This written testimony pertains to the Energy & Environmental 
Research Center's (EERC's) Plains CO2 Reduction (PCOR) 
Partnership and its role in carbon management in our region.
    The U.S. Department of Energy (DOE) National Energy Technology 
Laboratory has established the Regional Carbon Sequestration 
Partnership (RCSP) Program, which is focused on demonstrating the 
efficacy of carbon sequestration. The seven DOE partnerships (Figure 1) 
have developed capacity estimates for the major geologic sequestration 
targets and are currently conducting field validation tests across the 
United States and Canada. The PCOR Partnership at the EERC represents a 
diverse group of 68 public and private sector stakeholders (Figure 2) 
working together to better understand the technical and economic 
feasibility of capturing and storing CO2 emissions from 
stationary sources of CO2 in the central interior of North 
America.

[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]


    As part of the DOE RCSP Program, the PCOR Partnership region 
encompasses all or part of nine States and four Canadian provinces. The 
PCOR Partnership is managed by the EERC. The PCOR Partnership has 
developed a credible assessment of the region's major stationary 
CO2 sources and sinks and has mobilized the expertise and 
resources of the industries and local stakeholders who will be a major 
part of the ultimate success of carbon capture and storage (CCS) 
technologies. The progress has been rapid, the momentum is great, and 
the PCOR Partnership is poised to develop a commercial-scale 
CO2 sequestration project that will verify the scientific 
and economic efficacy of geologic sequestration. The next phase of the 
RCSP Program will result in the injection of 1 million tons or more of 
CO2 in each of the seven regions to assess large-scale 
sequestration in our Nation's varied geologic settings.
    The PCOR Partnership is catalyzing opportunities for sequestration 
in the region and identifying and resolving the technical, regulatory, 
and environmental barriers that will make carbon sequestration a near-
term reality. Throughout its existence, the PCOR Partnership has been 
engaging policy makers and the public regarding CO2 
emissions, sequestration strategies, and sequestration opportunities. 
The PCOR Partnership's members include all of the key stakeholders from 
within the region, along with additional stakeholders representing 
phenomenal global expertise--stakeholders representing expertise in 
energy exploration and production, engineering, geology, economics, 
agriculture, and the environment. PCOR Partnership members provide 
financial support as well as technical services to the PCOR Partnership 
by providing data, guidance, and practical experience.
    The PCOR Partnership is engaging the industries that will 
ultimately deploy this new technology. The PCOR Partnership's oil, gas, 
coal, and utility industry members are working together to develop 
commercially viable carbon management solutions. In the Williston Basin 
(Figure 3) of North Dakota, South Dakota, Montana, Saskatchewan, and 
Manitoba, the juxtaposition of major stationary CO2 sources 
(dominated by coal-fired power plants) and ideal potential sinks (oil 
and gas fields) facilitates the development of enhanced resource 
recovery opportunities. CO2-based enhanced oil and gas 
recovery could easily become a multi-billion-dollar opportunity for our 
region, resulting in benefits to the environment and energy industries. 
The favorable geology and socioeconomic conditions may allow our region 
to become an international showcase for the early implementation of 
CCS.

[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]


    The PCOR Partnership has developed a regional vision for carbon 
management that is based initially on enhanced resource recovery 
projects that build critical infrastructure and expertise for the long-
term deployment of CCS technologies. This approach will result in the 
reduction of greenhouse gases while supporting long-term economic 
growth on the continent.
    For more information on the PCOR Partnership, please see the fact 
sheets and Phase II Prospectus at http://www.undeerc.org/PCOR/products/
factsheet.asp.

                         CONCLUSION OF HEARING

    Senator Dorgan. Does anyone else at the witness table--did 
you want to add something, last words? If not, let me thank all 
of you for being here. This hearing is recessed.
    [Whereupon, at 11:19 a.m., Monday, August 13, the hearing 
was concluded, and the subcommittee was recessed, to reconvene 
subject to the call of the Chair.]

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